SEC Filing - Halliburton

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December 31, 2004 Form 10-K - Final

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2004

[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to __

Commission File Number 1-3492

HALLIBURTON COMPANY

(Exact name of registrant as specified in its charter)

Delaware	75-2677995
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
5 Houston Center
1401 McKinney, Suite 2400
Houston, Texas 77010
(Address of principal executive offices)
Telephone Number - Area code (713) 759-2600

Securities registered pursuant to Section 12(b) of the Act:

	Name of each Exchange on
Title of each class	which registered
Common Stock par value $2.50 per share	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No______

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

Yes X No ____

The aggregate market value of Common Stock held by nonaffiliates on June 30, 2004, determined using the per share closing price on the New York Stock Exchange Composite tape of $30.26 on that date was approximately $13,290,000,000.

As of February 17, 2005, there were 504,455,647 shares of Halliburton Company Common Stock, $2.50 par value per share, outstanding.

Portions of the Halliburton Company Proxy Statement for our 2005 Annual Meeting of Stockholders (File No. 1-3492) are incorporated by reference into Part III of this report.

HALLIBURTON COMPANY

Index to Form 10-K

For the Year Ended December 31, 2004

PART I		PAGE
Item 1.	Business	1
Item 2.	Properties	9
Item 3.	Legal Proceedings	10
Item 4.	Submission of Matters to a Vote of Security Holders	10
EXECUTIVE OFFICERS OF REGISTRANT		11
PART II
Item 5.	Market for the Registrant’s Common Equity and Related
	Stockholder Matters	13
Item 6.	Selected Financial Data	13
Item 7.	Management’s Discussion and Analysis of Financial
	Condition and Results of Operations	13
Item 7(a).	Quantitative and Qualitative Disclosures About Market Risk	13
Item 8.	Financial Statements and Supplementary Data	14
Item 9.	Changes in and disagreements with Accountants on
	Accounting and financial Disclosure	14
Item 9(a).	Controls and Procedures	14
Item 9(b).	Other Information	14
FINANCIAL STATEMENTS and MD&A
Management’s Discussion and Analysis of Financial Condition and
Results of Operations		15
Management’s Report on Internal Control Over Financial Reporting		62
Reports of Registered Public Accounting Firm		63
Consolidated Statements of Operations		65
Consolidated Balance Sheets		66
Consolidated Statements of Shareholder’s Equity		67
Consolidated Statements of Cash Flows		68
Notes to Consolidated Financial Statements		69
Selected Financial Data (Unaudited)		120
Quarterly Data and Market Price Information		121
PART III
Item 10.	Directors and Executive Officers of Registrant	122
Item 11.	Executive Compensation	122
Item 12(a).	Security Ownership of Certain Beneficial Owners	122
Item 12(b).	Security Ownership of Management	122
Item 12(c).	Changes in Control	122
Item 12(d).	Securities Authorized for Issuance Under Equity
	Compensation Plans	122
Item 13.	Certain Relationships and Related Transactions	122
Item 14.	Principal Accountant Fees and Services	122
PART IV
Item 15.	Exhibits and Financial Statement Schedules	123
SIGNATURES		135


	(i)

PART I

Item 1. Business.

General description of business. Halliburton Company’s predecessor was established in 1919 and incorporated under the laws of the State of Delaware in 1924. Halliburton Company provides a variety of services, products, maintenance, engineering, and construction to energy, industrial, and governmental customers.

Our six business segments are organized around how we manage the business: Production Optimization, Fluid Systems, Drilling and Formation Evaluation, Digital and Consulting Solutions (formerly Landmark and Other Energy Services), Government and Infrastructure, and Energy and Chemicals. We refer to the combination of Production Optimization, Fluid Systems, Drilling and Formation Evaluation, and Digital and Consulting Solutions segments as our Energy Services Group and to the Government and Infrastructure and Energy and Chemicals segments as KBR. See Note 5 to the consolidated financial statements for financial information about our business segments.

Asbestos and silica settlement and prepackaged Chapter 11 resolution. In December 2003, eight of our subsidiaries sought Chapter 11 protection to avail themselves of the provisions of Sections 524(g) and 105 of the Bankruptcy Code to discharge current and future asbestos and silica personal injury claims against us and our subsidiaries. The order confirming the plan of reorganization became final and nonappealable on December 31, 2004, and the plan of reorganization became effective in January 2005. Under the plan of reorganization, all current and future asbestos and silica personal injury claims against us and our affiliates were channeled into trusts established for the benefit of asbestos and si lica claimants, thus releasing us from those claims.

In accordance with the plan of reorganization, in January 2005 we contributed the following to trusts for the benefit of current and future asbestos and silica personal injury claimants:

approximately $2.3 billion in cash;

59.5 million shares of Halliburton common stock; and

notes currently valued at approximately $55 million.

During 2004, we settled insurance disputes with substantially all insurance companies for asbestos- and silica-related claims and all other claims under the applicable insurance policies and terminated all the applicable insurance policies. Under the terms of our insurance settlements, we will receive cash proceeds with a nominal amount of approximately $1.5 billion and with a present value of approximately $1.4 billion for our asbestos- and silica-related insurance receivables. Cash payments of approximately $1.0 billion related to these receivables were received in January 2005. Under the terms of the settlement agreements, we will receive cash payments of the remaining amounts in several installments beginning in July 2005 through 2009.

See Note 11 to the consolidated financial statements for further information regarding the resolution of our asbestos and silica settlement and prepackaged Chapter 11 proceedings.

Description of services and products. We offer a broad suite of products and services through our six business segments. The following summarizes our services and products for each business segment.

ENERGY SERVICES GROUP

Our Energy Services Group provides a wide range of discrete services and products, as well as bundled services and integrated services and solutions to customers for the exploration, development, and production of oil and gas. The Energy Services Group serves major, national, and independent oil and gas companies throughout the world.

Production Optimization

Our Production Optimization segment primarily tests, measures, and provides means to manage and/or improve well production once a well is drilled and, in some cases, after it has been producing. This segment consists of production enhancement services and completion tools and services.


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Production enhancement services include stimulation services, pipeline process services, sand control services, coiled tubing tools and services, and hydraulic workover services. Stimulation services optimize oil and gas reservoir production through a variety of pressure pumping services, and chemical processes, commonly known as fracturing and acidizing. Pipeline process services include pipeline and facility testing, commissioning, and cleaning via pressure pumping, chemical systems, specialty equipment, and nitrogen, and are provided to the midstream and downstream sectors of the energy business. Sand control services include fluid and chemical systems and pumping services for the prevention of formation sand production.

Completion tools and services include subsurface safety valves and flow control equipment, surface safety systems, packers and specialty completion equipment, intelligent completion systems, production automation, expandable liner hanger systems, sand control systems, slickline equipment and services, self-elevated workover platforms, tubing-conveyed perforating products and services, well servicing tools, and reservoir performance services. Reservoir performance services include drill stem and other well testing tools and services, underbalanced applications and real-time reservoir analysis, data acquisition services, and production applications.

Also included in this segment is WellDynamics, an intelligent well completions joint venture. In January 2004, Halliburton and Shell Technology Ventures (Shell) agreed to restructure two joint venture companies, WellDynamics B.V. (WellDynamics) and Enventure Global Technology LLC (Enventure), in an effort to more closely align the ventures with near-term priorities in the core businesses of the venture owners. We acquired an additional 1% of WellDynamics from Shell, giving us 51% ownership. With our resulting control of day-to-day operations, we believe we are now able to achieve more opportunities to leverage existing complementary businesses, reduce costs, and ensure global availability.

Additionally, subsea operations conducted by Subsea 7, Inc., of which we formerly owned 50%, are included in this segment. In January 2005, we completed the sale of this joint venture to our partner, Siem Offshore (formerly DSND Subsea ASA). See Note 4 to the consolidated financial statements for additional information related to this disposition.

Fluid Systems

Our Fluid Systems segment focuses on providing services and technologies to assist in the drilling and construction of oil and gas wells. This segment offers cementing and drilling fluids systems.

Cementing is the process used to bond the well and well casing while isolating fluid zones and maximizing wellbore stability. Cement and chemical additives are pumped to fill the space between the casing and the side of the wellbore. Our cementing service line also provides casing equipment and services.

Our Baroid Fluid Services product line provides drilling fluid systems, performance additives, solids control, and waste management services for oil and gas drilling, completion, and workover operations. In addition, Baroid Fluid Services sells products to a wide variety of industrial customers. Drilling fluids usually contain bentonite or barite in a water or oil base. Drilling fluids primarily improve wellbore stability and facilitate the transportation of cuttings from the bottom of a wellbore to the surface. Drilling fluids also help cool the drill bit, seal porous well formations, and assist in pressure control within a wellbore. Drilling fluids are often customized by onsite engineers for optimum stability and enhanced oil production.

Also included in this segment is our investment in Enventure, which is an expandable casing joint venture. As discussed above, in January 2004, Halliburton and Shell agreed to restructure this joint venture. Enventure was owned equally by Halliburton and Shell. Shell acquired an additional 33.5% of Enventure, leaving us with 16.5% ownership in return for enhanced and extended agreements and licenses with Shell for its Poroflex™ expandable sand screens and a distribution agreement for its Versaflex™ expandable liner hangers, in addition to a 1% increase in our ownership of WellDynamics.


	2

Drilling and Formation Evaluation

Our Drilling and Formation Evaluation segment is primarily involved in drilling and evaluating the formations during the bore-hole construction process. Major products and services offered include:

drilling systems and services;

drill bits; and

logging services.

Our Sperry Drilling Services product line provides drilling systems and services. These services include directional and horizontal drilling, measurement-while-drilling, logging-while-drilling, multilateral completion systems, and rig site information systems. Our drilling systems offer directional control while providing important measurements about the characteristics of the drill string and geological formations while drilling directional wells. Real-time operating capabilities enable the monitoring of well progress and aid decision-making processes.

Our Security DBS Drill Bits product line provides roller cone rock bits, fixed cutter bits, and related downhole tools used in drilling oil and gas wells. In addition, coring equipment and services are provided to acquire cores of the formations drilled for evaluation.

Logging services include open-hole wireline services which provide information on formation evaluation, including resistivity, porosity, and density; rock mechanics; and fluid sampling. Cased-hole services are also offered which provide cement bond evaluation, reservoir monitoring, pipe evaluation, pipe recovery, and perforating. Our Magnetic Resonance Imaging Logging (MRIL®) tools apply magnetic resonance imaging technology to the evaluation of subsurface rock formations in newly drilled oil and gas wells.

Digital and Consulting Solutions

Our Digital and Consulting Solutions segment provides integrated exploration and production software information systems, consulting services, real-time operations, subsea operations, and other integrated solutions.

Landmark Graphics is a supplier of integrated exploration and production software information systems as well as professional and data management services for the upstream oil and gas industry. Landmark Graphics software transforms vast quantities of seismic, well log, and other data into detailed computer models of petroleum reservoirs. The models are used by our customers to achieve optimal business and technical decisions in exploration, development, and production activities. Data management services provide efficient storage, browsing, and retrieval of large volumes of exploration and petroleum data. The products and services offered by Landmark Graphics integrate data workflows and operational processes across disciplines, including geophysics, geology, drilling, engineering, production, economics, finance a nd corporate planning, and key partners and suppliers.

This segment also provides value-added oilfield project management and integrated solutions to independent, integrated, and national oil companies. These offerings make use of all of Halliburton’s oilfield services, products, technologies, and project management capabilities to assist our customers in optimizing the value of their oil and gas assets.

KBR

KBR provides a wide range of services to energy and industrial customers and government entities worldwide and consists of two segments, Government and Infrastructure and Energy and Chemicals.

Government and Infrastructure

Our Government and Infrastructure segment focuses on:

construction, maintenance, and logistics services for government operations, facilities, and installations;

civil engineering, construction, consulting, and project management services for state and local government agencies and private industries;


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integrated security solutions, including threat definition assessments, mitigation, and consequence management; design, engineering and program management; construction and delivery; and physical security, operations, and maintenance;

dockyard operation and management through the Devonport Royal Dockyard Limited (DML) subsidiary, with services that include design, construction, surface/subsurface fleet maintenance, nuclear engineering and refueling, and weapons engineering; and

privately financed initiatives, in which KBR funds the development or provision of an asset, such as a facility, service, or infrastructure for a government client, which we then own, operate and maintain, enabling our clients to utilize new assets at a reasonable cost.

Energy and Chemicals

Our Energy and Chemicals segment is a global engineering, procurement, construction, technology, and services provider for the energy and chemicals industries. Working both upstream and downstream in support of our customers, Energy and Chemicals offers the following:

downstream engineering and construction capabilities, including global engineering execution centers, as well as engineering, construction, and program management of liquefied natural gas, ammonia, petrochemicals, crude oil refineries, and natural gas plants;

upstream deepwater engineering, marine technology, and project management;

Production Services provides plant operations, maintenance, and start-up services for upstream oil and gas facilities worldwide;

in the United States, Industrial Services provides maintenance services to the petrochemical, forest product, power, and commercial markets;

industry-leading licensed technologies in the areas of fertilizers and synthesis gas, olefins, refining, and chemicals and polymers; and

consulting services in the form of expert technical and management advice that include studies, conceptual and detailed engineering, project management, construction supervision and design, and construction verification or certification in both upstream and downstream markets.

Also included in this segment are two joint ventures: TSKJ, in which we have a 25% interest, and M. W. Kellogg, Ltd., in which we have a 55% interest. TSKJ was formed to construct and subsequently expand a large natural gas liquefaction complex in Nigeria.

Dispositions in 2004. In August 2004, we sold our surface well testing and subsea test tree operations within our Production Optimization segment to Power Well Service Holdings, LLC, an affiliate of First Reserve Corporation. This disposition will have an immaterial impact on our future operations. See Note 4 to the consolidated financial statements for additional information related to this disposition.

Business strategy. Our business strategy is to maintain global leadership in providing energy services and products and engineering and construction services. We provide these services and products to our customers as discrete services and products and, when combined with project management services, as integrated solutions. Our ability to be a global leader depends on meeting four key goals:

establishing and maintaining technological leadership;

achieving and continuing operational excellence;

creating and continuing innovative business relationships; and

preserving a dynamic workforce.

Now that we have resolved our asbestos and silica liability and our affected subsidiaries have exited Chapter 11 reorganization proceedings, we intend to separate KBR from Halliburton, which could include a transaction involving a spin-off, split-off, public offering, or sale of KBR or its operations. In order to maximize KBR’s value for our shareholders and to determine the most appropriate form of the transaction and its components, it may be necessary for KBR to establish a track record of positive earnings for a number of quarters and to seek resolution of governmental issues, investigations, and other disputes.


	4

Markets and competition. We are one of the world’s largest diversified energy services and engineering and construction services companies. We believe that our future success will depend in large part upon our ability to offer a wide array of services and products on a global scale. Our services and products are sold in highly competitive markets throughout the world. Competitive factors impacting sales of our services and products include:

price;

service delivery (including the ability to deliver services and products on an “as needed, where needed” basis);

health, safety, and environmental standards and practices;

service quality;

product quality;

warranty; and

technical proficiency.

While we provide a wide range of discrete services and products, a number of customers have indicated a preference for bundled services and integrated services and solutions. In the case of the Energy Services Group, integrated services and solutions relate to all phases of exploration, development, and production of oil, natural gas, and natural gas liquids. In the case of KBR, integrated services and solutions relate to all phases of design, procurement, construction, project management, and maintenance of facilities primarily for energy and government customers.

We conduct business worldwide in over 100 countries. In 2004, based on the location of services provided and products sold, 26% of our consolidated revenue was from Iraq, primarily related to our work for the United States Government, and 22% of our consolidated revenue was from the United States. In 2003, 27% of our consolidated revenue was from the United States and 15% of our consolidated revenue was from Iraq. No other country accounted for more than 10% of our consolidated revenue during these periods. See Note 5 to the consolidated financial statements for additional financial information about geographic operations in the last three years. Since the markets for our services and products are vast and cross numerous geographic lines, a meaningful estimate of the total number of competitors cannot be made. The industries we serve are highly competitive and we have many substantial competitors. Largely all of our services and products are marketed through our servicing and sales organizations.

Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism, civil unrest, expropriation or other governmental actions, and exchange control and currency problems. Except for our government services work in Iraq discussed above, we believe the geographic diversification of our business activities reduces the risk that loss of operations in any one country would be material to the conduct of our operations taken as a whole.

Information regarding our exposures to foreign currency fluctuations, risk concentration, and financial instruments used to minimize risk is included in Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial Instrument Market Risk and in Note 18 to the consolidated financial statements.

Customers and backlog. Our revenue during the past three years was mainly derived from the sale of services and products to the energy industry, including 54% in 2004, 66% in 2003, and 86% in 2002. Revenue from the United States Government, resulting primarily from the work performed in the Middle East by our Government and Infrastructure segment, represented 39% of our 2004 consolidated revenue and 26% of our 2003 consolidated revenue. Revenue from the United States Government during 2002 represented less than 10% of consolidated revenue. No other customer represented more than 10% of consolidated revenue in any period presented.


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The following schedule summarizes our project backlog:

	December 31
Millions of dollars	2004		2003
Firm orders:
Government and Infrastructure	$	3,968	$	5,025
Energy and Chemicals		3,643		3,625
Energy Services Group segments		64		278
Total		7,675		8,928
Government orders firm but not yet funded,
letters of intent, and contracts awarded
but not signed:
Government and Infrastructure		816		1,076
Energy and Chemicals		-		19
Energy Services Group segments		-		43
Total		816		1,138
Total backlog	$	8,491	$	10,066

Backlog related to Subsea 7, Inc. is not included in the table above at December 31, 2004 since it was sold subsequent to year-end. We estimate that 74% of backlog existing within the Government and Infrastructure segment and 51% of backlog existing within the Energy and Chemicals segment at December 31, 2004 will be completed during 2005. Approximately 75% of total backlog relates to cost-reimbursable contracts with the remaining 25% relating to fixed-price contracts. For contracts that are not for a specific amount, backlog is estimated as follows:

operations and maintenance contracts that cover multiple years are included in backlog based upon an estimate of the work to be provided over the next twelve months; and

government contracts that cover a broad scope of work up to a maximum value are included in backlog at the estimated amount of work to be completed under the contract based upon periodic consultation with the customer.

For projects where we act as project manager, we only include our scope of each project in backlog. For projects related to unconsolidated joint ventures, we only include our percentage ownership of each joint venture’s backlog, which totaled $1.1 billion at December 31, 2004. Our backlog excludes contracts for recurring hardware and software maintenance and support services offered by Landmark Graphics. Backlog is not indicative of future operating results because backlog figures are subject to substantial fluctuations. Arrangements included in backlog are in many instances extremely complex, nonrepetitive in nature, and may fluctuate in contract value and timing. Many contracts do not provide for a fixed amount of work to be performed and are subject to modification or termination by the customer. The termi nation or modification of any one or more sizeable contracts or the addition of other contracts may have a substantial and immediate effect on backlog.

Raw materials. Raw materials essential to our business are normally readily available. Where we rely on a single supplier for materials essential to our business, we are confident that we could make satisfactory alternative arrangements in the event of an interruption in supply.

Research and development costs. We maintain an active research and development program. The program improves existing products and processes, develops new products and processes, and improves engineering standards and practices that serve the changing needs of our customers. Our expenditures for research and development activities were $234 million in 2004, $221 million in 2003, and $233 million in 2002, of which over 96% was company-sponsored in each year.


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Patents. We own a large number of patents and have pending a substantial number of patent applications covering various products and processes. We are also licensed to utilize patents owned by others. We do not consider any particular patent or group of patents to be material to our business operations.

Seasonality. On an overall basis, our operations are not generally affected by seasonality. Weather and natural phenomena can temporarily affect the performance of our services, but the widespread geographical locations of our operations serve to mitigate those effects. Examples of how weather can impact our business include:

the severity and duration of the winter in North America can have a significant impact on gas storage levels and drilling activity for natural gas;

the timing and duration of the spring thaw in Canada directly affects activity levels due to road restrictions;

typhoons and hurricanes can disrupt offshore operations; and

severe weather during the winter months normally results in reduced activity levels in the North Sea.

Due to higher spending near the end of the year on capital expenditures by customers for software, Landmark Graphics results of operations are generally stronger in the fourth quarter of the year than at the beginning of the year.

Employees. At December 31, 2004, we employed approximately 97,000 people worldwide compared to 101,000 at December 31, 2003. At December 31, 2004, approximately 6% of our employees were subject to collective bargaining agreements. Based upon the geographic diversification of these employees, we believe any risk of loss from employee strikes or other collective actions would not be material to the conduct of our operations taken as a whole.

Environmental regulation. We are subject to numerous environmental, legal, and regulatory requirements related to our operations worldwide. In the United States, these laws and regulations include, among others:

the Comprehensive Environmental Response, Compensation and Liability Act;

the Resources Conservation and Recovery Act;

the Clean Air Act;

the Federal Water Pollution Control Act; and

the Toxic Substances Control Act.

In addition to the federal laws and regulations, states and other countries where we do business may have numerous environmental, legal, and regulatory requirements by which we must abide. We evaluate and address the environmental impact of our operations by assessing and remediating contaminated properties in order to avoid future liabilities and comply with environmental, legal, and regulatory requirements. On occasion, we are involved in specific environmental litigation and claims, including the remediation of properties we own or have operated, as well as efforts to meet or correct compliance-related matters. Our Health, Safety and Environment group has several programs in place to maintain environmental leadership and to prevent the occurrence of environmental contamination.

We do not expect costs related to these remediation requirements to have a material adverse effect on our consolidated financial position or our results of operations.

Website access. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 are made available free of charge on our internet website at www.halliburton.com as soon as reasonably practicable after we have electronically filed the material with, or furnished it to, the Securities and Exchange Commission. We have posted on our website our Code of Business Conduct, which applies to all of our employees and Directors and serves as a code


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of ethics for our principal executive officer, principal financial officer, principal accounting officer or controller, and other persons performing similar functions. Any amendments to our Code of Business Conduct or any waivers from provisions of our Code of Business Conduct granted to the specified officers above are disclosed on our website within four business days after the date of any amendment or waiver pertaining to these officers.


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Item 2. Properties.

We own or lease numerous properties in domestic and foreign locations. The following locations represent our major facilities:

Location	Owned/Leased	Description
*Energy Services Group*
North America
Production Optimization Segment:

Carrollton, Texas	Owned	Manufacturing facility

Alvarado, Texas	Owned/Leased	Manufacturing facility

Drilling and Formation
Evaluation Segment:

The Woodlands, Texas	Leased	Manufacturing facility

Shared Facilities:

Duncan, Oklahoma	Owned	Manufacturing, technology, and campus
		facilities

Houston, Texas	Owned	Manufacturing and campus facilities

Houston, Texas	Owned/Leased	Campus facility

Houston, Texas	Leased	Campus facility

*KBR*
North America
Energy and Chemicals Segment:

Houston, Texas	Leased	Campus facility

Shared Facilities:

Houston, Texas	Owned	Campus facility

Europe/Africa
Shared Facilities:

Leatherhead, United Kingdom	Owned	Campus facility

*Corporate*
Houston, Texas	Leased	Corporate executive offices

All of our owned properties are unencumbered.

In addition, we have 155 international and 106 United States field camps from which the Energy Services Group delivers its products and services. We also have numerous small facilities that include sales offices, project offices, and bulk storage facilities throughout the world. We own or lease marine fabrication facilities covering approximately 519 acres in Texas, England (primarily related to DML), and Scotland, which are used by KBR. Our marine facilities located in Texas and Scotland are currently for sale.


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We have mineral rights to proven and probable reserves of barite and bentonite. These rights include leaseholds, mining claims, and owned property. We process barite and bentonite for use in our Fluid Systems segment in addition to supplying many industrial markets worldwide. Based on the number of tons of bentonite consumed in fiscal year 2004, we estimate that our 20 million tons of proven reserves in areas of active mining are sufficient to fulfill our internal and external needs for the next 15 years. We estimate that our 2.8 million tons of proven reserves of barite in areas of active mining equate to a 16-year supply based on current rates of production. These estimates are subject to change based on periodic updates to reserve estimates and to the extent future consumption differs from current levels of con sumption.

We believe all properties that we currently occupy are suitable for their intended use.

Item 3. Legal Proceedings.

Information relating to various commitments and contingencies is described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Forward-Looking Information and Risk Factors” and in Notes 3, 11, 12, and 13 to the consolidated financial statements.

Item 4. Submission of Matters to a Vote of Security Holders.

There were no matters submitted to a vote of security holders during the fourth quarter of 2004.


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Executive Officers of the Registrant.

The following table indicates the names and ages of the executive officers of the registrant as of February 15, 2005, along with a listing of all offices held by each during the past five years:

Name and Age	Offices Held and Term of Office
* Albert O. Cornelison, Jr.	Executive Vice President and General Counsel of Halliburton Company,
(Age 55)	since December 2002
	Vice President and General Counsel of Halliburton Company, May
	2002 to December 2002
	Vice President and Associate General Counsel of Halliburton Company,
	October 1998 to May 2002

* C. Christopher Gaut	Executive Vice President and Chief Financial Officer of Halliburton
(Age 48)	Company, since March 2003
	Senior Vice President, Chief Financial Officer and Member - Office of
	the President and Chief Operating Officer of ENSCO International
	Incorporated, January 2002 to February 2003
	Senior Vice President and Chief Financial Officer of ENSCO
	International Incorporated, December 1987 to December 2001

W. Preston Holsinger	Vice President and Treasurer of Halliburton Company, since
(Age 63)	October 2004
	Director, Special Projects, May 2002 to October 2004
	Shared Services Director HED/IS, November 1998 to May 2002

* Andrew R. Lane	Executive Vice President and Chief Operating Officer, since
(Age 45)	December 2004
	President and Chief Executive Officer of KBR, July 2004 to
	November 2004
	Senior Vice President, Global Operations of Halliburton Energy
	Services, April 2004 to July 2004
	President, Landmark Division of Halliburton Energy Services Group,
	May 2003 to March 2004
	President and Chief Executive Officer of Landmark Graphics, April
	2002 to April 2003
	Chief Operating Officer of Landmark Graphics, January 2002 to
	March 2002
	Vice President, Production Enhancement PSL, Completion Products
	PSL and Tools/Testing/TCP of Halliburton Energy Services Group,
	January 2000 to December 2001


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Name and Age	Offices Held and Term of Office
* David J. Lesar	Chairman of the Board, President and Chief Executive Officer of
(Age 51)	Halliburton Company, since August 2000
	Director of Halliburton Company, since August 2000
	President and Chief Operating Officer of Halliburton Company, May
	1997 to August 2000
	Chairman of the Board of Kellogg Brown & Root, Inc., January 1999 to
	August 2000
	Executive Vice President and Chief Financial Officer of Halliburton
	Company, August 1995 to May 1997

Mark A. McCollum	Senior Vice President and Chief Accounting Officer, since August 2003
(Age 45)	Senior Vice President and Chief Financial Officer, Tenneco
	Automotive, Inc., November 1999 to August 2003

* Weldon J. Mire	Vice President, Human Resources of Halliburton Company, since May
(Age 57)	2002
	Division Vice President of Halliburton Energy Services, January 2001
	to May 2002 (Country Vice President Indonesia)
	Asia Pacific Sales Manager of Halliburton Energy Services, November
	1999 to January 2001
	Director of Business Development, September 1999 to November 1999
	Global Director of Strategic Business Development, January 1999 to
	November 1999
	Senior Shared Services Manager Houston, November 1998 to
	January 1999

David R. Smith	Vice President, Tax of Halliburton Company, since May 2002
(Age 58)	Vice President, Tax of Halliburton Energy Services, Inc., September
	1998 to May 2002

* Members of the Policy Committee of the registrant.

There are no family relationships between the executive officers of the registrant or between any director and any executive officer of the registrant.


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PART II

Item 5. Market for the Registrant’s Common Equity and Related Stockholder Matters.

Halliburton Company’s common stock is traded on the New York Stock Exchange. Information relating to the high and low market prices of common stock and quarterly dividend payments is included under the caption “Quarterly Data and Market Price Information” on page 121 of this annual report. Cash dividends on common stock for 2004 and 2003 in the amount of $0.125 per share were paid in March, June, September, and December of each year. Our Board of Directors intends to consider the payment of quarterly dividends on the outstanding shares of our common stock in the future. The declaration and payment of future dividends, however, will be at the discretion of the Board of Directors and will depend upon, among other things, future earnings, general financial condition and liquidity, success in busin ess activities, capital requirements, and general business conditions.

At February 15, 2005, there were approximately 22,573 shareholders of record. In calculating the number of shareholders, we consider clearing agencies and security position listings as one shareholder for each agency or listing.

Following is a summary of our repurchases of our common stock during the three-month period ended December 31, 2004.


					Total Number
					of Shares
					Purchased
					as Part of
					Publicly
	Total Number		Average		Announced
	of Shares		Price Paid		Plans or
Period	Purchased (a)		per Share		Programs
October 1-31		4,145	$	31.57		-
November 1-30		20,414	$	33.81		-
December 1-31		8,219	$	36.32		-
Total		32,778	$	34.16		-

(a) All of the shares repurchased during the three-month period ended December 31, 2004 were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted stock grants. These share purchases were not part of a publicly announced program to purchase common shares.

On April 25, 2000, our Board of Directors approved plans to implement a share repurchase program for up to 44 million shares of our common stock, of which 22,385,700 shares may yet be purchased.

Item 6. Selected Financial Data.

Information relating to selected financial data is included on page 120 of this annual report.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Information relating to Management’s Discussion and Analysis of Financial Condition and Results of Operations is included on pages 15 through 61 of this annual report.

Item 7(a). Quantitative and Qualitative Disclosures About Market Risk.

Information relating to market risk is included in Management’s Discussion and Analysis of Financial Condition and Results of Operations under the caption “Financial Instrument Market Risk” on page 48 of this annual report.


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Item 8. Financial Statements and Supplementary Data.

	Page No.
Management’s Report on Internal Control Over Financial Reporting	62
Reports of Independent Registered Public Accounting Firm	63-64
Consolidated Statements of Operations for the years ended
December 31, 2004, 2003, and 2002	65
Consolidated Balance Sheets at December 31, 2004 and 2003	66
Consolidated Statements of Shareholders’ Equity for the years ended
December 31, 2004, 2003, and 2002	67
Consolidated Statements of Cash Flows for the years ended
December 31, 2004, 2003, and 2002	68
Notes to Consolidated Financial Statements	69-119
Selected Financial Data (Unaudited)	120
Quarterly Data and Market Price Information (Unaudited)	121

The related financial statement schedules are included under Part IV, Item 15 of this annual report.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9(a). Controls and Procedures.

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2004 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedure s include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There has been no change in our internal control over financial reporting that occurred during the three months ended December 31, 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

See page 62 for Management’s Report on Internal Control Over Financial Reporting and page 64 for Report of Independent Registered Public Accounting Firm on our assessment of internal control over financial reporting and opinion on the effectiveness of the Company’s internal control over financial reporting.

Item 9(b). Other Information.

None.


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HALLIBURTON COMPANY

Management’s Discussion and Analysis of Financial Condition and Results of Operations

EXECUTIVE OVERVIEW

The past year was marked with several milestones, including:

the finalization of our asbestos and silica settlements and our subsidiaries’ related emergence from Chapter 11 proceedings. We funded the trusts in January 2005 with $2.3 billion in cash and 59.5 million shares of our common stock. We received approximately $1.0 billion in cash during January 2005 under the terms of our insurance settlement agreements;

achieving record revenue of over $20 billion, driven by our government services work in the Middle East and strong performance in our Energy Services Group, where we increased our international presence. Our Energy Services Group also had record levels of revenue, operating income, and operating margins;

reaching an important agreement with our customer for the Barracuda-Caratinga project, which settled all claims and change orders, as well as adjusted the project scope and various milestone dates. We also achieved 92% project completion as a result of the Barracuda vessel producing first oil and the Caratinga vessel moving offshore for sea trials and final inspections. Subsequently, the Caratinga vessel achieved first oil in February 2005;

restructuring KBR, which we expect will yield between $80 million and $100 million in annual savings; and

addressing our liquidity needs in anticipation of funding the asbestos and silica trusts while managing our working capital position related to our government services work in the Middle East. This included utilizing two accounts receivable facilities during 2004, issuing $500 million of senior notes due 2007 in January 2004, maintaining one revolving credit facility, and arranging a new $500 million revolving credit facility during 2004. As of December 31, 2004, the two revolving credit facilities had available credit totaling $1.028 billion.

During 2004, we continued to provide substantial work under our government contracts business to the United States Department of Defense and other governmental agencies, including worldwide United States Army logistics contracts, known as LogCAP, and contracts to rebuild Iraq’s petroleum industry, known as RIO and PCO Oil South. Total revenue from the United States Government for 2004 includes $8.0 billion, or 39% of consolidated revenue, and revenue related to Iraq (which includes Kuwait) totaled approximately $7.1 billion, or 35% in 2004.

Detailed discussions of asbestos and silica, our United States government contract work, the Nigerian joint venture and investigations, the Barracuda-Caratinga project, and our liquidity and capital resources follow. Our operating performance, including our recent restructuring of KBR, is described in “Business Environment and Results of Operations” below.

Looking ahead, the outlook for our business is positive. Current market conditions for our energy services business are good with strong commodity prices, and our customers are increasing their exploration and production budgets. We are well-positioned in sectors that are experiencing particularly strong activity, such as United States onshore gas, and in areas that could experience increased activity in the near term, such as the deepwater Gulf of Mexico. In addition to the benefits expected from our recent restructuring initiative at KBR, we will continue to pursue our natural gas monetization strategy and push forward on the definitization process of our United States government contracts in the Middle East. Finally, now that we have resolved our asbestos and silica liability and our affected subsidiaries have exited Chapter 11 reorganization


	15

proceedings, we intend to separate KBR from Halliburton, which could include a transaction involving a spin-off, split-off, public offering, or sale of KBR or its operations. In order to maximize KBR’s value for our shareholders and to determine the most appropriate form of the transaction and its components, it may be necessary for KBR to establish a track record of positive earnings for a number of quarters and to seek resolution of governmental issues, contract investigations, and other disputes.

Asbestos and Silica Obligations and Insurance Recoveries

Prepackaged Chapter 11 proceedings. DII Industries, Kellogg Brown & Root, Inc. (Kellogg Brown & Root), and six other subsidiaries (Mid-Valley, Inc.; KBR Technical Services, Inc.; Kellogg Brown & Root Engineering Corporation; Kellogg Brown & Root International, Inc. (a Delaware corporation); Kellogg Brown & Root International, Inc. (a Panamanian corporation); and BPM Minerals, LLC) filed Chapter 11 proceedings on December 16, 2003 in bankruptcy court in Pittsburgh, Pennsylvania. Each of these entities was a wholly owned subsidiary of Halliburton before, during, and after the bankruptcy proceedings became final.

Our subsidiaries sought Chapter 11 protection to avail themselves of the provisions of Sections 524(g) and 105 of the Bankruptcy Code to discharge current and future asbestos and silica personal injury claims against us and our subsidiaries. The order confirming the plan of reorganization became final and nonappealable on December 31, 2004, and the plan of reorganization became effective in January 2005. Under the plan of reorganization, all current and future asbestos and silica personal injury claims against us and our affiliates were channeled into trusts established for the benefit of asbestos and silica claimants, thus releasing us from those claims.

In accordance with the plan of reorganization, in January 2005 we contributed the following to trusts for the benefit of current and future asbestos and silica personal injury claimants:

approximately $2.345 billion in cash, which represents the remaining portion of the $2.775 billion total cash settlement after payments of $311 million in December 2003 and $119 million in June 2004;

59.5 million shares of Halliburton common stock;

a one-year non-interest-bearing note of $31 million for the benefit of asbestos claimants. We prepaid the initial installment on the note of approximately $8 million in January 2005. The remaining note will be paid in three equal quarterly installments starting in the second quarter of 2005; and

a silica note with an initial payment into a silica trust of $15 million. Subsequently, the note provides that we will contribute an amount to the silica trust at the end of each year for the next 30 years of up to $15 million. The note also provides for an extension of the note for 20 additional years under certain circumstances. We have estimated the value of this note to be approximately $24 million. We will periodically reassess our valuation of this note based upon our projections of the amounts we believe we will be required to fund into the silica trust.

As a result of the filing of the Chapter 11 proceedings, we adjusted the asbestos and silica liability to reflect the amount of the proposed settlement and certain related costs, which resulted in a pre-tax charge of approximately $1.016 billion to discontinued operations in the fourth quarter of 2003. The tax effect on this charge was minimal, as a valuation allowance was established against the liability to reflect the expected net tax benefit from the future deductions the liability will create.


	16

former operations that have been divested and included in discontinued operations. Consequently, all 2003 and 2004 changes in our estimates related to the asbestos and silica liability were recorded through discontinued operations.

Our plan of reorganization called for a portion of our total asbestos liability to be settled by contributing 59.5 million shares of Halliburton common stock to the trust. As of December 31, 2004, we revalued our shares to approximately $2.335 billion ($39.24 per share), an increase of $778 million from December 31, 2003, and this amount was charged to discontinued operations on our consolidated statement of operations during 2004. Effective December 31, 2004, concurrent with receiving final and nonappealable confirmation of our plan of reorganization, we reclassified from a long-term liability to shareholders’ equity the final value of the 59.5 million shares of Halliburton common stock. If the shares had been included in the calculation of earnings per share as of the beginning of 2004, our diluted earnings per share from continuing operations would have been reduced by $0.11 for 2004.

Insurance settlements. During 2004, we settled insurance disputes with substantially all the insurance companies for asbestos- and silica-related claims and all other claims under the applicable insurance policies and terminated all the applicable insurance policies. Under the terms of our insurance settlements, we will receive cash proceeds with a nominal amount of approximately $1.5 billion and with a present value of approximately $1.4 billion for our asbestos- and silica-related insurance receivables. The present value was determined by discounting the expected future cash payments with a discount rate implicit in the settlements, which ranged from 4.0% to 5.5%. Beginning in the third quarter of 2004, this disco unt is being accreted as interest income (classified as discontinued operations) over the life of the expected future cash payments. Cash payments of approximately $1.0 billion related to these receivables were received in January 2005. Under the terms of the settlement agreements, we will receive cash payments of the remaining amounts in several installments beginning in July 2005 through 2009.

Our December 31, 2003 estimate of our asbestos- and silica-related insurance receivables already included a charge for the settlement amount under an agreement reached in January 2004, as well as certain other probable settlements with companies for which we could reasonably estimate the amount of the settlement. During 2004, we reduced the amount recorded as insurance receivables for asbestos- and silica-related liabilities insured by other companies based upon the final agreements, resulting in pretax charges to discontinued operations of approximately $698 million.

United States Government Contract Work

Our operations under United States government contracts are regularly reviewed and audited by the Defense Contract Audit Agency (DCAA) and other governmental agencies. The DCAA serves in an advisory role to our customer. When issues are found during the governmental agency audit process, these issues are typically discussed and reviewed with us. The DCAA then issues an audit report with their recommendations to our customer’s contracting officer. In the case of management systems and other contract administrative issues, the contracting officer is generally with the Defense Contract Management Agency (DCMA). We then work with our customer to resolve the issues noted in the audit report.

Given the demands of working in Iraq and elsewhere for the United States government, we expect that from time to time we will have disagreements or experience performance issues with the various government customers for which we work. If our performance is unacceptable to our customer under any of our government contracts, the government retains the right to pursue remedies under any affected contract, which remedies could include threatened termination or termination. If any contract were so terminated, we may not receive award fees under the affected contract, and our ability to


	17

secure future contracts could be adversely affected, although we would receive payment for amounts owed for our allowable costs under cost-reimbursable contracts.

Fuel. In December 2003, the DCAA issued a preliminary audit report that alleged that we may have overcharged the Department of Defense by $61 million in importing fuel into Iraq. The DCAA questioned costs associated with fuel purchases made in Kuwait that were more expensive than buying and transporting fuel from Turkey. We responded that we had maintained close coordination of the fuel mission with the Army Corps of Engineers (COE), which was our customer and oversaw the project, throughout the life of the task order and that the COE had directed us to use the Kuwait sources. After a review, the COE concluded that we obtained a fair price for the fuel. However, Department of Defense officials thereafter referred th e matter to the agency’s inspector general, which we understand has commenced an investigation.

The DCAA has issued various audit reports related to task orders under the RIO contract that reported $304 million in questioned and unsupported costs. The majority of these costs are associated with the humanitarian fuel mission. In these reports, the DCAA has compared fuel costs we incurred during the duration of the RIO contract in 2003 and early 2004 to fuel prices obtained by the Defense Energy Supply Center (DESC) in April 2004 when the fuel mission was transferred to that agency. We are working with our customer to resolve this issue.

Investigations. On January 22, 2004, we announced the identification by our internal audit function of a potential overbilling of approximately $6 million by La Nouvelle Trading & Contracting Company, W.L.L. (La Nouvelle), one of our subcontractors, under the LogCAP contract in Iraq, for services performed during 2003. In accordance with our policy and government regulation, the potential overcharge was reported to the Department of Defense Inspector General’s office as well as to our customer, the AMC. On January 23, 2004, we issued a check in the amount of $6 million to the AMC to cover that potential overbilling while we conducted our own investigation into the matter. Later in the first quarter of 2004, we determined that the amount of overbilling was $4 million, and the subcontractor billing should have been $2 million for the services provided. As a result, we paid La Nouvelle $2 million and billed our customer that amount. We subsequently terminated La Nouvelle’s services under the LogCAP contract. In October 2004, La Nouvelle filed suit against us alleging $224 million in damages as a result of its termination. We are continuing to investigate whether La Nouvelle paid, or attempted to pay, one or two of our former employees in connection with the billing. See Note 13 to our consolidated financial statements for further discussion.

In October 2004, we reported to the Department of Defense Inspector General’s office that two former employees in Kuwait may have had inappropriate contacts with individuals employed by or affiliated with two third-party subcontractors prior to the award of the subcontracts. The Inspector General’s office may investigate whether these two employees may have solicited and/or accepted payments from these third-party subcontractors while they were employed by us.

In October 2004, a civilian contracting official in the COE asked for a review of the process used by the COE for awarding some of the contracts to us. We understand that the Department of Defense Inspector General’s office may review the issues involved.

We understand that the United States Department of Justice, an Assistant United States Attorney based in Illinois, and others are investigating these and other individually immaterial matters we have reported relating to our government contract work in Iraq. We also understand that current and former employees of KBR have received subpoenas and have given or may give grand jury testimony relating to some of these matters. If criminal wrongdoing were found, criminal penalties could range up to the greater of $500,000 in fines per count for a corporation, or twice the gross pecuniary gain or loss.


	18

directed us to support and the number of soldiers counted at dining facilities for United States troops and supporting civilian personnel. In the first quarter of 2004, we reviewed our DFAC subcontracts in our Iraq and Kuwait areas of operation and have billed and continue to bill for all current DFAC costs. During 2004, we received notice from the DCAA that it was recommending withholding a portion of our DFAC billings. For DFAC billings relating to subcontracts entered into prior to February 2004, the DCAA has recommended withholding 19.35% of the billings until it completes its audits. Subsequent to February 2004, we renegotiated our DFAC subcontracts to address the specific issues raised by the DCAA and advised the AMC and the DCAA of the new terms of the arrangements. We have had no objection by the government to the terms and conditions associated with these new DFAC subcontract agreements. During the third quarter of 2004, we received notification that, for three Kuwait DFACs, the DCAA recommended to our customer that costs be disallowed because the DCAA is not satisfied with the level of documentation provided by us. The amount withheld related to suspended and recommended disallowed DFAC costs for work performed prior to February 2004 and totaled approximately $224 million as of December 31, 2004. The amount withheld could change as the DCAA continues their audits of the remaining DFAC facilities. We are negotiating with our customer, the AMC, to resolve this issue. We are currently withholding a proportionate amount of these billings from our subcontractors.

Laundry. During the third quarter of 2004, we received notice from the DCAA that it recommended withholding $16 million of subcontract costs related to the laundry service for one task order in southern Iraq for which it believes we and our subcontractors have not provided adequate levels of documentation supporting the quantity of the services provided. The DCAA recommended that the cost be withheld pending receipt of additional explanation or documentation to support subcontract cost. This $16 million was withheld from the subcontractor in the fourth quarter of 2004. We are working with the AMC to resolve this issue.

Withholding of payments. During 2004, the AMC issued a determination that a particular contract clause could cause it to withhold 15% from our invoices until our task orders under the LogCAP contract are definitized. The AMC delayed implementation of this withholding pending further review. The Army Field Support Command (AFSC) has now been delegated authority by the AMC to determine whether or not to implement the withholding. The AFSC has informed us that it will assess the situation on a task order by task order basis and, currently, withholding will continue to be delayed. We do not believe any potential 15% withholding will have a significant or sustained impact on our liquidity because any withholding is temporary and ends once the definitization process is complete. During the third quarter of 2004, we and the AMC identified three senior management teams to facilitate negotiation under the LogCAP task orders, and these teams are working to negotiate outstanding issues and definitize task orders as quickly possible. We are continuing to work with our customer to resolve outstanding issues. As of January 18, 2005, 25 task orders for LogCAP totaling over $636 million have been definitized.

As of December 31, 2004, the COE had withheld $85 million of our invoices related to a portion of our RIO contract pending completion of the definitization process. All 10 definitization proposals required under this contract have been submitted by us, and three have been finalized through a task order modification. After review by the DCAA, we have resubmitted five of the unfinalized seven proposals and are in the process of developing revised proposals for the remaining two. These withholdings represent the amount invoiced in excess of 85% of the funding in the task order. The COE also could withhold similar amounts from future invoices under our RIO contract until agreement is reached with the customer and task order modifications are issued. Approximately $2 million was withheld from our PCO Oil South project as of December 31, 2004. The PCO Oil South project has definitized 15 of the 28 task orders and withholdings are not continuing on those task orders. We do not believe the withholding will have a significant or sustained impact on our liquidity because the withholding is temporary and ends once the definitization process is complete.


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In addition, we had unapproved claims totaling $93 million at December 31, 2004 for the LogCAP, RIO, and PCO Oil South contracts. These unapproved claims related to contracts where our costs have exceeded the funded value of the task order or were related to lost, damaged and destroyed equipment.

We are working diligently with our customers to proceed with significant new work only after we have a fully definitized task order, which should limit withholdings on future task orders.

Cost reporting. We have received notice that a contracting officer for our PCO Oil South project considers our monthly categorization and detail of costs and our ability to schedule and forecast costs to be inadequate, and he has requested corrections be made by March 10, 2005. We expect to be able to make the requested corrections. If we were unable to satisfy our customer, our customer may pursue remedies under the applicable federal acquisition regulations, including terminating the affected contract. Although there can be no assurances, we do not expect that our work on the PCO Oil South project will be terminated for default. We are in the process of developing an acceptable management cost reporting system and are supplementing the existing PCO cost reporting team with additional manpower.

Report on estimating system. On December 27, 2004, the DCMA granted continued approval of our estimating system, stating that our estimating system is “acceptable with corrective action.” We are in process of completing these corrective actions. Specifically, based on the unprecedented level of support our employees are providing the military in Iraq, Kuwait, and Afghanistan, we needed to update our estimating policies and procedures to make them better suited to such contingency situations. Additionally, we are in process of developing a detailed training program that will be made avai lable to all estimating personnel to ensure that employees are adequately prepared to deal with the challenges and unique circumstances associated with a contingency operation.

Report on purchasing system. As a result of a Contractor Purchasing System Review by the DCMA during the second quarter of 2004, the DCMA granted the continued approval of our government contract purchasing system. The DCMA’s approval letter, dated September 7, 2004, stated that our purchasing system’s policies and practices are “effective and efficient, and provide adequate protection of the Government’s interest.”

The Balkans. We have had inquiries in the past by the DCAA and the civil fraud division of the United States Department of Justice into possible overcharges for work performed during 1996 through 2000 under a contract in the Balkans, which inquiry has not yet been completed by the Department of Justice. Based on an internal investigation, we credited our customer approximately $2 million during 2000 and 2001 related to our work in the Balkans as a result of billings for which support was not readily available. We believe that the preliminary Department of Justice inquiry relates to potential overcharges in connection with a part of the Balkans contract under which approximately $100 million in work was done. We beli eve that any allegations of overcharges would be without merit.

Nigerian joint venture and investigations

Foreign Corrupt Practices Act investigation. The United States Securities and Exchange Commission (SEC) is conducting a formal investigation into payments made in connection with the construction and subsequent expansion by TSKJ of a multibillion dollar natural gas liquefaction complex and related facilities at Bonny Island in Rivers State, Nigeria. The United States Department of Justice is also conducting an investigation. TSKJ is a private limited liability company registered in Madeira, Portugal whose members are Technip SA of France, Snamprogetti Netherlands B.V., which is an affiliate of ENI SpA of Italy, JGC Corporation of Japan, and Kellogg Brown & Root, each of which owns 25% of the venture.


	20

Root, and to other current and former Kellogg Brown & Root employees. We further understand that the Department of Justice has invoked its authority under a sitting grand jury to obtain letters rogatory for the purpose of obtaining information abroad.

TSKJ and other similarly owned entities entered into various contracts to build and expand the liquefied natural gas project for Nigeria LNG Limited, which is owned by the Nigerian National Petroleum Corporation, Shell Gas B.V., Cleag Limited (an affiliate of Total), and Agip International B.V., which is an affiliate of ENI SpA of Italy. Commencing in 1995, TSKJ entered into a series of agency agreements in connection with the Nigerian project. We understand that a French magistrate has officially placed Jeffrey Tesler, a principal of Tri-Star Investments, an agent of TSKJ, under investigation for corruption of a foreign public official. In Nigeria, a legislative committee of the National Assembly and the Economic and Financial Crimes Commission, which is organized as part of the executive branch of the government , are also investigating these matters. Our representatives have met with the French magistrate and Nigerian officials and expressed our willingness to cooperate with those investigations. In October 2004, representatives of TSKJ voluntarily testified before the Nigerian legislative committee.

As a result of our continuing investigation into these matters, information has been uncovered suggesting that, commencing at least 10 years ago, the members of TSKJ considered payments to Nigerian officials. We provided this information to the United States Department of Justice, the SEC, the French magistrate, and the Nigerian Economics and Financial Crimes Commission. We also notified the other owners of TSKJ of the recently uncovered information and asked each of them to conduct their own investigation.

We understand from the ongoing governmental and other investigations that payments may have been made to Nigerian officials. In addition, TSKJ has suspended the receipt of services from and payments to Tri-Star Investments and is considering instituting legal proceedings to declare all agency agreements with Tri-Star Investments terminated and to recover all amounts previously paid under those agreements.

We also understand that the matters under investigation by the Department of Justice involve parties other than Kellogg Brown & Root and M.W. Kellogg, Ltd. (a joint venture in which Kellogg Brown & Root has a 55% interest), cover an extended period of time (in some cases significantly before our 1998 acquisition of Dresser Industries (which included M.W. Kellogg, Ltd.)), and possibly include the construction of a fertilizer plant in Nigeria in the early 1990s and the activities of agents and service providers.

In June 2004, we terminated all relationships with Mr. Stanley and another consultant and former employee of M.W. Kellogg, Ltd. The terminations occurred because of violations of our Code of Business Conduct that allegedly involve the receipt of improper personal benefits in connection with TSKJ’s construction of the natural gas liquefaction facility in Nigeria.

In February 2005, TSKJ notified the Attorney General of Nigeria that TSKJ would not oppose the Attorney General’s efforts to have sums of money held on deposit in banks in Switzerland transferred to Nigeria and to have the legal ownership of such sums determined in the Nigerian courts.

If violations of the FCPA were found, we could be subject to civil penalties of $500,000 per violation, and criminal penalties could range up to the greater of $2 million per violation or twice the gross pecuniary gain or loss.

There can be no assurance that any governmental investigation or our investigation of these matters will not conclude that violations of applicable laws have occurred or that the results of these investigations will not have a material adverse effect on our business and results of operations.


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engaged in coordinated bidding with one or more competitors on certain foreign construction projects and that such coordination possibly began as early as the mid-1980s, which was significantly before our 1998 acquisition of Dresser Industries.

On the basis of this information, we and the Department of Justice have broadened our investigations to determine the nature and extent of any improper bidding practices, whether such conduct violated United States antitrust laws, and whether former employees may have received payments in connection with bidding practices on some foreign projects.

If violations of applicable United States antitrust laws occurred, the range of possible penalties includes criminal fines, which could range up to the greater of $10 million in fines per count for a corporation, or twice the gross pecuniary gain or loss, and treble civil damages in favor of any persons financially injured by such violations. If such violations occurred, the United States government also would have the discretion to deny future government contracts business to KBR or affiliates or subsidiaries of KBR. Criminal prosecutions under applicable laws of relevant foreign jurisdictions and civil claims by or relationship issues with customers are also possible.

There can be no assurance that the results of these investigations will not have a material adverse effect on our business and results of operations.

Barracuda-Caratinga Project

In June 2000, Kellogg Brown & Root, Inc. entered into a contract with Barracuda & Caratinga Leasing Company B.V., the project owner, to develop the Barracuda and Caratinga crude oilfields, which are located off the coast of Brazil. The construction manager and project owner’s representative is Petrobras, the Brazilian national oil company. When completed, the project will consist of two converted supertankers, Barracuda and Caratinga, which will be used as floating production, storage, and offloading units, commonly referred to as FPSOs. In addition, there will be 32 hydrocarbon production wells, 22 water injection wells, and all subsea flow lines, umbilicals, and risers necessary to connect the underwater wells to the FPSOs. The original completion date for the Barracuda vessel was December 2003, and the original completion date for the Caratinga vessel was April 2004. The project has been significantly behind the original schedule, due in part to change orders from the project owner, and is in a financial loss position.

In December 2004, the Barracuda vessel achieved first oil after being moved offshore for sea trials and final inspections in October 2004 and the Caratinga vessel was moved offshore for sea trials and final inspections. The Caratinga vessel achieved first oil in February 2005. Pursuant to the settlement agreement with Petrobras described below, the Barracuda vessel must be completed by March 31, 2006, and the Caratinga vessel must be completed by June 30, 2006. While we anticipate meeting these completion targets, there can be no assurance that further delays will not occur.

Also in December 2004, Kellogg Brown & Root and Petrobras, on behalf of the project owner, reached an agreement to settle various claims between the parties. The agreement provides for:

the release of all claims of all parties that arise prior to the effective date of a final definitive agreement;

a payment to us in 2005 of $79 million as a result of change orders for remaining claims;

payment by Petrobras of applicable value added taxes on the project, except for $8 million which has been paid by us;

the performance by Petrobras of certain work under the original contract;

the repayment by Kellogg Brown & Root of $300 million of advance payments by the end of February 2005, with interest on $74 million. Of this amount, $79 million was paid in 2004; and

revised milestones and other dates, including settlement of liquidated damages and an extension of time to the FPSO final acceptance dates.


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As of December 31, 2004:

the project was approximately 92% complete;

we have recorded an inception-to-date loss of $762 million related to the project, of which $407 million was recorded in 2004, $238 million was recorded in 2003, and $117 million was recorded in 2002;

the losses recorded include an estimated $24 million in liquidated damages based on the final agreement with Petrobras; and

the probable unapproved claims were reduced from $114 million at December 31, 2003 to zero based upon the final agreement with Petrobras.

Cash flow considerations. We have now begun to fund operating cash shortfalls on the project and are obligated to fund total shortages over the remaining project life. Estimated cash flows relating to the losses are as follows:

Millions of dollars
Amount funded through December 31, 2004	$	586
Amounts to be paid/(received) in 2005:
Remaining repayment of $300 million advance		221
Payment to us relating to change orders		(138	)
Remaining project costs, net of revenue to be
received		93
Total cash shortfalls	$	762

LIQUIDITY AND CAPITAL RESOURCES

We ended 2004 with cash and cash equivalents of $2.8 billion compared to $1.8 billion at the end of 2003. Our cash and cash equivalents balance at the end of January 2005, after funding of the asbestos and silica liability trusts and receipt of insurance proceeds discussed below, was approximately $1.7 billion.

Significant sources of cash. Our liquidity position was strong at the end of 2004 due to our positive cash flow from operations, new debt financing, sales of accounts receivable, and our controlled capital spending in 2004. Our operations provided approximately $928 million in cash flow in 2004, including the sale of accounts receivables discussed below. In addition, our cash flow was supplemented by cash totaling $126 million from the sale of our surface well testing operations in August 2004 and $20 million from the sale of our remaining shares of National Oilwell, Inc. in February 2004.

In January 2004, we issued senior notes due 2007 totaling $500 million, which were issued in anticipation of funding the asbestos and silica liability trusts. Our combined short-term notes payable and long-term debt was 50% of total capitalization at December 31, 2004, compared to 58% at the end of 2003 and 30% at the end of 2002. While our debt balance increased, the decrease in our ratio of debt-to-total-capitalization was due to the reclassification to shareholders’ equity of the value of the 59.5 million shares to be contributed to the asbestos trust in our consolidated balance sheet as of December 31, 2004.

In May 2004, we entered into an agreement to sell, assign, and transfer the entire title and interest in specified United States government accounts receivable of KBR to a third party. The total amount outstanding under this agreement as of December 31, 2004 was approximately $263 million. Subsequent to year-end 2004, these receivables were collected and the balance retired, and we are not currently selling further receivables, although the facility continues to be available.

In June 2004, we sold undivided interests totaling $268 million under our Energy Services Group securitization facility. As of December 31, 2004, we have $256 million outstanding under this facility. See “Off Balance Sheet Risk” below for further discussion regarding these facilities.


	23

Future sources of cash. We have available to us significant sources of cash in the near term should we need them.

Revolving credit facilities. In the fourth quarter of 2003, we entered into a secured $700 million three-year revolving credit facility for general working capital purposes. In July 2004, we entered into an additional secured $500 million 364-day revolving credit facility for general working capital purposes with terms substantially similar to our $700 million revolving credit facility. As of December 31, 2004, we had issued a letter of credit for approximately $172 million under the $700 million revolving credit facility, which replaced a letter of credit expiring on our Barracuda-Caratinga project, thus reducing the availability under that revolving credit facility to $528 million. There were no cash drawings unde r the $700 million revolving credit facility or the $500 million 364-day revolving credit facility as of December 31, 2004.

Asbestos and silica settlements with insurance companies. During 2004, we settled insurance disputes with substantially all the insurance companies for asbestos- and silica-related claims and all other claims under the applicable insurance policies and terminated all the applicable insurance policies. Under the terms of our insurance settlements, we expect to receive cash proceeds with a nominal value of $1.5 billion and a present value of approximately $1.4 billion for our asbestos- and silica-related insurance receivables as follows:

Millions of dollars
2005	$	1,066
2006		162
2007		40
2008		45
2009		131
Thereafter		16
Total	$	1,460

We received approximately $1.0 billion in insurance proceeds in January 2005. We intend to use a substantial portion of these proceeds to reduce debt.

Other. In January 2005, we received approximately $200 million in cash proceeds from the sale of our 50% interest in Subsea 7, Inc.

In June 2004, a Texas district court jury returned a verdict in our favor in connection with a patent infringement lawsuit we filed against Smith International (Smith) in September 2002. We were awarded $41 million in damages and legal fees by the court. Because the verdict is currently under appeal by Smith, the timing of ultimate collection of this award is uncertain.

Significant uses of cash. Our liquidity and cash balance during 2004 was significantly affected by our government services work in Iraq. Our working capital requirements for our Iraq-related work, excluding cash and equivalents, were down from $885 million at the end of 2003 to approximately $700 million at December 31, 2004. We do not expect a further increase in our working capital investments above that amount.

In connection with reaching an agreement with representatives of asbestos and silica claimants to limit the cash required to settle pending claims to $2.775 billion, DII Industries paid $311 million to the claimants in December 2003, plus an additional $22 million in lieu of interest. We also agreed to guarantee the payment of certain claims, and, in accordance with settlement agreements, we made additional payments of $119 million, plus an additional $4 million in lieu of interest, in June 2004.

Capital expenditures of $575 million in 2004 were 12% higher than in 2003. Capital spending in 2004 continued to be primarily directed to the Energy Services Group for Production Optimization, Drilling and Formation Evaluation, and manufacturing capacity.


	24

We paid $221 million in dividends to our shareholders in 2004 compared to $219 million in 2003 and 2002.

In April 2004, we paid the $107 million judgment amount in the BJ Services Company patent litigation, including pre- and post-judgment interest, with the funds that had been used to post bond in the case. In April 2004, we also reached a settlement with the plaintiffs in the Anglo-Dutch (Tenge) litigation and made all payments pursuant to the settlement agreement. During the second quarter of 2004, we recovered the $25 million cash-in-lieu-of-bond deposit for the Anglo-Dutch (Tenge) litigation formerly included in restricted cash.

Future use of cash. In January 2005, we made the following payments for our asbestos and silica liability settlement:

Millions of dollars
Cash payments made in January 2005:
Payment to the asbestos and silica trust in accordance with
the plan of reorganization	$	2,345
Cash payment related to insurance partitioning agreement
reached with Federal-Mogul in October 2004 - first
of three installments		16
First installment payment for the silica note		15
Payments related to RHI Refractories agreement		11
First of four installments for the one-year non-interest-
bearing note of $31 million for the benefit of
asbestos claimants		8
Total cash payments made in January 2005	$	2,395

The following table summarizes our significant contractual obligations and other long-term liabilities as of December 31, 2004:

	Payments due
Millions of dollars	2005		2006		2007		2008		2009		Thereafter		Total
Long-term debt (1)	$	347	$	293	$	518	$	156	$	-	$	2,625	$	3,939
Asbestos and silica
settlement
payment		2,345		-		-		-		-		-		2,345
Operating leases		158		125		104		92		82		453		1,014
Purchase obligations (3)		363		18		18		18		12		11		440
Barracuda-Caratinga		176		-		-		-		-		-		176
Pension funding
obligations		77		-		-		-		-		-		77
Asbestos insurance
partitioning
agreement		16		15		15		-		-		-		46
Asbestos note		31		-		-		-		-		-		31
Silica note (2)		15		1		1		1		1		5		24
RHI Refractories		11		-		-		-		-		-		11
Total	$	3,539	$	452	$	656	$	267	$	95	$	3,094	$	8,103


	25

(1) Long-term debt excludes the effect of a terminated interest rate swap of approximately $5 million. See Note 10 to the consolidated financial statements for further discussion.

(2) Subsequent to the initial payment of $15 million, the silica note provides that we will contribute an amount to the silica trust at the end of each year for the next 30 years of up to $15 million. The note also provides for an extension of the note for 20 additional years under certain circumstances. We have recorded the note at our estimated amount of approximately $24 million. We will periodically reassess our valuation of this note based upon our projections of the amounts we believe we will be required to fund into the silica trust.

(3) The purchase obligations disclosed above do not include purchase obligations that KBR enters into with its vendors in the normal course of business that support existing contracting arrangements with its customers. The purchase obligations with their vendors can span several years depending on the duration of the projects. In general, the costs associated with the purchase obligations are expensed as the revenue is earned on the related projects.

Capital spending for 2005 is expected to be approximately $650 million. The capital expenditures budget for 2005 includes increased activities at our DML shipyard, software spending as KBR moves forward with the implementation of SAP, and higher spending in the Energy Services Group to accommodate increased business.

As of December 31, 2004, we had commitments to fund approximately $58 million to certain of our related companies. These commitments arose primarily during the start-up of these entities or due to losses incurred by them. We expect approximately $42 million of the commitments to be paid during the next year.

Other factors affecting liquidity

Letters of credit. In the normal course of business, we have agreements with banks under which approximately $1.1 billion of letters of credit or bank guarantees were outstanding as of December 31, 2004 including $264 million which relate to our joint ventures’ operations. Also included in letters of credit outstanding as of December 31, 2004 and related to the Barracuda-Caratinga project were $277 million of performance letters of credit and $176 million of retainage letters of credit. Certain of the outstanding letters of credit have triggering events which would entitle a bank to require cash collateralization.

In the fourth quarter of 2003, we entered into a senior secured master letter of credit facility (Master LC Facility) with a syndicate of banks which covered at least 90% of the face amount of our existing letters of credit. The facility expired on December 31, 2004 due to our plan of reorganization becoming final and nonappealable. We did not have any outstanding advances under the Master LC Facility when it expired. Upon the expiration of the Master LC Facility, all letters of credit under the facility reverted back to the original agreements with the individual banks.

Debt covenants. Certain of our letters of credit, our $700 million revolving credit facility, and our $500 million 364-day revolving credit facility contain restrictive covenants including covenants that require us to maintain certain financial ratios as defined by the agreements. For certain of our letters of credit and the two revolving credit facilities we are required to maintain an interest coverage ratio of 3.5 or greater and a leverage ratio less than or equal to 0.55. At December 31, 2004, our interest coverage ratio was 7.18 and our leverage ratio was 0.42. Borrowings under the revolving credit facilities will be secured by certain of our assets until our long-term senior unsecured debt is rated BBB or high er (stable outlook) by Standard & Poor’s and Baa2 or higher (stable outlook) by Moody’s Investors Service.

To the extent that the aggregate principal amount of all secured indebtedness exceeds 5% of the consolidated net tangible assets of Halliburton and its subsidiaries, all collateral will be shared pro rata with holders of Halliburton’s 8.75% debentures due 2021, 3.125% convertible senior notes due 2023, senior notes due 2005, 5.5% senior notes due 2010, medium-term notes, 7.6% debentures due 2096, senior notes issued in January 2004 due 2007 and any other new issuance to the extent that the issuance contains a requirement that the holders thereof be equally and ratably secured with


	26

Halliburton’s other secured creditors. At December 31, 2004, 5% of our consolidated net tangible assets as calculated based on the agreement was $392 million, and the total aggregate amount of our secured debt outstanding was approximately $50 million.

BUSINESS ENVIRONMENT AND RESULTS OF OPERATIONS

We currently operate in over 100 countries throughout the world, providing a comprehensive range of discrete and integrated products and services to the energy industry and to other industrial and governmental customers. The majority of our consolidated revenue is derived from the sale of services and products, including engineering and construction activities. We sell services and products primarily to major, national, and independent oil and gas companies and the United States government. The products and services provided to the major national, and independent oil and gas companies are used throughout the energy industry from the earliest phases of exploration, development, and production of oil and gas resources through refining, processing, and marketing. Our six business segments are organized around how we manage the business: Production Optimization, Fluid Systems, Drilling and Formation Evaluation, Digital and Consulting Solutions, Government and Infrastructure, and Energy and Chemicals. We refer to the combination of Production Optimization, Fluid Systems, Drilling and Formation Evaluation, and Digital and Consulting Solutions segments as the Energy Services Group, and the combination of Government and Infrastructure and Energy and Chemicals as KBR.

The industries we serve are highly competitive with many substantial competitors for each segment. In 2004, based upon the location of the services provided and products sold, 26% of our consolidated revenue was from Iraq, primarily related to our work for the United States government, and 22% of our consolidated revenue was from the United States. In 2003, 27% of our consolidated revenue was from the United States and 15% of our consolidated revenue was from Iraq. No other country accounted for more than 10% of our revenue during these periods.

Operations in some countries may be adversely affected by unsettled political conditions, acts of terrorism, civil unrest, force majeure, war or other armed conflict, expropriation or other governmental actions, inflation, exchange controls, or currency devaluation. Except for our government services work in Iraq discussed above, we believe the geographic diversification of our business activities reduces the risk that loss of operations in any one country would be material to our consolidated results of operations.

Halliburton Company

Activity levels within our business segments are significantly impacted by the following:

spending on upstream exploration, development, and production programs by major, national, and independent oil and gas companies;

capital expenditures for downstream refining, processing, petrochemical, and marketing facilities by major, national, and independent oil and gas companies; and

government spending levels.

Also impacting our activity is the status of the global economy, which indirectly impacts oil and gas consumption, demand for petrochemical products, and investment in infrastructure projects.

Energy Services Group

Some of the more significant barometers of current and future spending levels of oil and gas companies are oil and gas prices, exploration and production activities by international and national oil companies, the world economy, and global stability, which together drive worldwide drilling activity. Our Energy Services Group financial performance is significantly affected by oil and gas prices and worldwide rig activity which are summarized in the following tables.


	27

This table shows the average oil and gas prices for West Texas Intermediate crude oil and Henry Hub natural gas prices:

Average Oil and Gas Prices	2004		2003		2002
West Texas Intermediate oil
prices (dollars per barrel)	$	41.31	$	31.14	$	25.92
Henry Hub gas prices (dollars per
million cubic feet)	$	5.85	$	5.63	$	3.33

The yearly average rig counts based on the Baker Hughes Incorporated rig count information are as follows:

Average Rig Counts	2004		2003		2002
Land vs. Offshore
United States:
Land		1,093		924		718
Offshore		97		108		113
Total		1,190		1,032		831
Canada:
Land		365		368		260
Offshore		4		4		6
Total		369		372		266
International (excluding Canada):
Land		594		544		507
Offshore		242		226		225
Total		836		770		732
Worldwide total		2,395		2,174		1,829
Land total		2,052		1,836		1,485
Offshore total		343		338		344

Average Rig Counts	2004		2003		2002
Oil vs. Gas
United States:
Oil		165		157		137
Gas		1,025		875		694
Total		1,190		1,032		831
* Canada:		369		372		266
International (excluding Canada):
Oil		648		576		561
Gas		188		194		171
Total		836		770		732
Worldwide total		2,395		2,174		1,829

* Canadian rig counts by oil and gas were not available.

Our customers’ cash flows, in many instances, depend upon the revenue they generate from sale of oil and gas. With higher prices, they may have more cash flow, which usually translates into higher exploration and production budgets. Higher prices may also mean that oil and gas exploration in marginal areas can become attractive, so our customers may


	28

consider investing in such properties when prices are high. When this occurs, it means more potential work for us. The opposite is true for lower oil and gas prices.

Over 2004, oil prices trended upward to over $50 per barrel in October due to low petroleum inventory levels in the United States and Organization for Economic Cooperation and Development countries, uncertainties caused by potential disruption of crude supplies in Iraq, Russia, Saudi Arabia, Nigeria, Norway, and Venezuela, and increased demand in the United States and Asia markets reflecting improved year-over-year economies. Since October, prices have retreated somewhat as the Organization of the Petroleum Exporting Countries increased production in order to restock low inventories, and more than half of the production capacity that was closed because of Hurricane Ivan in September has been reopened. On average, natural gas prices in 2004 gained some ground compared to the already-elevated prices of 2003. As high oil costs have promoted switching to natural gas as a fuel substitute, demand for natural gas has strengthened. Thus, higher petroleum prices have lifted natural gas prices, despite the fact that natural gas in storage is at the upper end of the five-year average. Additionally, there are still large volumes of Gulf Coast gas supply which remain offline due to Hurricane Ivan damage.

Most of our work in the Energy Services Group closely tracks the number of active rigs. As rig count increases or decreases, so does the total available market for our services and products. Further, our margins associated with services and products for offshore rigs are generally higher than those associated with land rigs.

Heightened demand coupled with high petroleum and natural gas prices in 2004 contributed to a 10% increase in average worldwide rig count compared to 2003. This increase was primarily driven by the United States rig count, which grew 15% year-over-year. Land gas drilling in the United States rose sharply, as gas prices remained high due to economic demand growth, severe weather disruptions in the Gulf of Mexico, and higher fuel oil prices that discouraged switching to a lower-priced fuel source to minimize cost. Average Canadian rig counts remained relatively flat year-over-year. Outside of North America, average rig counts increased in Latin America, Asia Pacific, and the Middle East, with the entire increase related to oil production. In Europe, where average rig counts declined compared to 2003, oil company dis satisfaction with high operating costs and inconsistent government policies impeded exploration and production recovery.

It is common practice in the United States oilfield services industry to sell services and products based on a price book and then apply discounts to the price book based upon a variety of factors. The discounts applied typically increase to partially or substantially offset price book increases in the weeks immediately following a price increase. The discount applied normally decreases over time if the activity levels remain strong. During periods of reduced activity, discounts normally increase, reducing the net revenue for our services and conversely, during periods of higher activity, discounts normally decline resulting in net revenue increasing for our services.

In May 2004, we implemented United States price book increases ranging between 5% and 8%, followed in October by an 11% United States price book increase in our pumping services. We worked diligently to minimize the impact of inflationary pressures in our cost base in 2004 and are maintaining a steady focus on capital discipline. Consequently, we expect to realize continued benefits of these price book increases in 2005.

We have made a decision to be very selective about pursuing turn-key drilling projects in the future. As has been experienced within the energy services industry, these types of projects are inherently risky and may not provide sufficient upside to offset this risk.

Overall outlook. Strong growth in the demand for oil worldwide, particularly in China, India, and other developing countries, is generally cited as the driving force behind the sharp oil price increases seen over the past three years. The single most important factor behind high prices in 2004 was the largest annual gain in world oil demand since 1978. The Energy Information Administration forecasts world petroleum demand growth for 2005-2006 to remain strong but down from the demand growth seen in 2004.


	29

Based on its exploration and production expenditure survey for 2005, Lehman Brothers expects worldwide exploration and production spending in 2005 to increase over 2004 spending, predominantly in the United States and Canada. Spears and Associates predicted that operators as a group will increase their activity in terms of rigs, wells, and footage in the range of 4% to 6% in most regions in 2005. Spears and Associates forecasted a 4% increase in United States rigs, with a 5% rise offshore. Thus, the three-year downturn in the United States offshore rig count is expected to end in 2005. International drilling activity is predicted to turn in another solid year of growth in 2005, with Spears and Associates projecting a 5% increase in international rig count.

We are well-positioned in the strong growth sectors noted above. In pressure pumping, we have a leading share of the United States onshore gas market. We are also well-positioned in the offshore segments that could experience a rebound over the next several quarters, particularly the deepwater Gulf of Mexico. Furthermore, given the tightness of service company capacity, customers are increasingly seeking to secure oilfield services with longer-term contracts. In the fourth quarter of 2004, we won a series of major contracts onshore in the United States gas sector, and internationally in Russia, Algeria, and the Middle East.

Finally, technology is an important aspect of our business, and we have focused on improving the development and introduction of new technologies. In 2004, we realized growth in our new product and service sales. In 2005, we expect to continue to invest in technology at the same level as 2004.

KBR

KBR provides a wide range of services to energy and industrial customers and government entities worldwide. KBR projects are generally longer term in nature than our Energy Services Group work and are impacted by more diverse drivers than short term fluctuations in oil and gas prices and drilling activities.

Effective October 1, 2004, we restructured KBR into two segments, Government and Infrastructure and Energy and Chemicals. As a result of the reorganization and in a continued effort to better position KBR for the future, we made several strategic organizational changes. We eliminated certain internal expenditures; we refocused our research and development expenditures with emphasis on the more profitable liquefied natural gas (LNG) market; and, we took appropriate steps to streamline the entire organization. We expect to yield between $80 million and $100 million in annual savings due to our reorganization.

In our Government and Infrastructure segment, our government services work is forecasted to grow in all regions, with United States government spending in Iraq outpacing other markets. Our work in Iraq continues to be our largest revenue contributor within this segment. We continue to make progress with our LogCAP, RIO, and PCO Oil South customers on definitizing our cost proposals. Going forward, we expect activity in Iraq to decline, but not as much as we had previously anticipated.

Within our Energy and Chemicals segment, the major focus is on our gas monetization work. Forecasted LNG market growth remains strong in a range of 7% to 10% annual growth through 2010, with demand indicated to double in the period through 2015. Significant numbers of new LNG liquefaction plant and LNG receiving terminal projects are proposed worldwide and are in various stages of development. Committed LNG liquefaction engineering, procurement, and construction projects are now yielding substantial growth in worldwide LNG liquefaction capacity. This trend is expected to continue through 2007 and beyond.

Outsourcing of operations and maintenance work by industrial and energy companies has been increasing worldwide. Even greater opportunities in this area are anticipated as the aging infrastructure in United States refineries and chemical plants require more maintenance and repairs to minimize production downtime. More stringent industry safety standards and environmental regulations also tend to lead to higher maintenance standards and costs.


	30

Contract structure. Engineering and construction contracts can be broadly categorized as either cost-reimbursable or fixed-price, sometimes referred to as lump sum. Some contracts can involve both fixed-price and cost-reimbursable elements. Fixed-price contracts are for a fixed sum to cover all costs and any profit element for a defined scope of work. Fixed-price contracts entail more risk to us as we must predetermine both the quantities of work to be performed and the costs associated with executing the work.

Cost-reimbursable contracts include contracts where the price is variable based upon actual costs incurred for time and materials, or for variable quantities of work priced at defined unit rates. Profit elements on cost-reimbursable contracts may be based upon a percentage of costs incurred and/or a fixed amount. Cost-reimbursable contracts are generally less risky, since the owner retains many of the risks. While fixed-price contracts involve greater risk, they also are potentially more profitable for the contractor, since the owners pay a premium to transfer many risks to the contractor.

The approximate percentages of revenue attributable to fixed-price and cost-reimbursable contracts within KBR are as follows:

	Fixed-Price			Cost-Reimbursable
2004		17	%		83	%
2003		24	%		76	%
2002		47	%		53	%

The increase in percentage of revenue attributable to cost-reimbursable contracts over the past two years reflects increased revenue from our government services work in Iraq as well as our continuing strategy to move away from fixed-price contracts within our Energy and Chemical segment.

We have two remaining major fixed-price engineering, procurement, installation, and commissioning, or EPIC, offshore projects. As of December 31, 2004, they are substantially complete.

The reshaping of our offshore business away from lump-sum EPIC contracts to cost reimbursement services has been marked by some significant new work. During the first quarter of 2004 we signed a major reimbursable engineering, procurement, and construction management, or EPCM, contract for a West African oilfield development. This is a major award under our new EPCM strategy. We are also pursuing program management opportunities in deepwater locations around the world. These efforts, implemented under our new strategy, are allowing us to utilize our global resources to continue to be a leader in the offshore business.


	31

RESULTS OF OPERATIONS IN 2004 COMPARED TO 2003

REVENUE:

Increase/

Percentage

Millions of dollars

2004

2003

(Decrease)

Change

Production Optimization

$

3,303

$

2,758

$

545

20

%

Fluid Systems

2,324

2,039

285

14

Drilling and Formation Evaluation

1,782

1,643

139

8

Digital and Consulting Solutions

589

555

34

6

Total Energy Services Group

7,998

6,995

1,003

14

Government and Infrastructure

9,393

5,417

3,976

73

Energy and Chemicals

3,075

3,859

(784

)

(20

)

Total KBR

12,468

9,276

3,192

34

Total revenue

$

20,466

$

16,271

$

4,195

26

%

Geographic - Energy Services Group segments only:

Production Optimization:

North America

$

1,694

$

1,337

$

357

27

%

Latin America

335

317

18

6

Europe/Africa

695

562

133

24

Middle East/Asia

579

542

37

7

Subtotal

3,303

2,758

545

20

Fluid Systems:

North America

1,104

990

114

12

Latin America

338

258

80

31

Europe/Africa

502

452

50

11

Middle East/Asia

380

339

41

12

Subtotal

2,324

2,039

285

14

Drilling and Formation Evaluation:

North America

610

558

52

9

Latin America

281

261

20

8

Europe/Africa

344

312

32

10

Middle East/Asia

547

512

35

7

Subtotal

1,782

1,643

139

8

Digital and Consulting Solutions:

North America

201

200

1

1

Latin America

128

71

57

80

Europe/Africa

124

116

8

7

Middle East/Asia

136

168

(32

)

(19

)

Subtotal

589

555

34

6

Total Energy Services Group revenue

by region:

North America

3,609

3,085

524

17

Latin America

1,082

907

175

19

Europe/Africa

1,665

1,442

223

15

Middle East/Asia

1,642

1,561

81

5

Total Energy Services Group revenue

$

7,998

$

6,995

$

1,003

14

%


	32

*OPERATING INCOME (LOSS):*								Increase/			Percentage
Millions of dollars		2004			2003			(Decrease)			Change
Production Optimization		$	633		$	413		$	220			53	%
Fluid Systems			348			251			97			39
Drilling and Formation Evaluation			225			177			48			27
Digital and Consulting Solutions			60			(15	)		75			NM
Total Energy Services Group			1,266			826			440			53
Government and Infrastructure			84			194			(110	)		(57	)
Energy and Chemicals			(426	)		(225	)		(201	)		(89	)
Shared KBR			-			(5	)		5			100
Total KBR			(342	)		(36	)		(306	)		NM
General corporate			(87	)		(70	)		(17	)		(24	)
Operating income		$	837		$	720		$	117			16	%

Geographic - Energy Services Group segments only:
Production Optimization:
North America	$376				$	194		$	182			94	%
Latin America	56					75			(19	)		(25	)
Europe/Africa	99					52			47			90
Middle East/Asia	102					92			10			11
Subtotal	633					413			220			53
Fluid Systems:
North America	186					104			82			79
Latin America	55					52			3			6
Europe/Africa	61					48			13			27
Middle East/Asia	46					47			(1	)		(2	)
Subtotal	348					251			97			39
Drilling and Formation Evaluation:
North America	102					60			42			70
Latin America	24					30			(6	)		(20	)
Europe/Africa	31					30			1			3
Middle East/Asia	68					57			11			19
Subtotal	225					177			48			27
Digital and Consulting Solutions:
North America	58					(52	)		110			212
Latin America	(5)					8			(13	)		(163	)
Europe/Africa	(5)					17			(22	)		(129	)
Middle East/Asia	12					12			-			-
Subtotal	60					(15	)		75			NM
Total Energy Services Group
operating income by region:
North America	722					306			416			136
Latin America	130					165			(35	)		(21	)
Europe/Africa	186					147			39			27
Middle East/Asia	228					208			20			10
Total Energy Services Group
operating income	$1,266				$	826		$	440			53	%

NM - Not Meaningful


	33

The increase in consolidated revenue in 2004 compared to 2003 was largely attributable to activity in our government services projects, primarily in the Middle East, and to increased sales of our Energy Services Group products and services as a result of the overall increase in worldwide rig counts. International revenue was 78% of consolidated revenue in 2004 and 73% of consolidated revenue in 2003, with the increase attributable to our government services projects abroad. Revenue from the United States Government for all geographic areas was approximately $8.0 billion or 39% of consolidated revenue in 2004 compared to $4.2 billion or 26% of consolidated revenue in 2003.

The increase in consolidated operating income was primarily due to stronger performance in our Energy Services Group resulting from favorable changes in oil and gas prices, which increased worldwide rig counts, and pricing improvements in the United States in the current year. The table below provides significant items included in segment operating income.

	Years ended December 31
Millions of dollars	2004			2003
Production Optimization:
Surface well testing gain on sale	$	54		$	-
HMS gain on sale		-			24
Drilling and Formation Evaluation:
Mono Pumps gain on sale		-			36
Digital and Consulting Solutions:
Integrated solutions project
losses in Mexico		(33	)		-
Anglo-Dutch lawsuit		13			(77	)
Intellectual property settlement		(11	)		-
Wellstream loss on sale		-			(15	)
Government and Infrastructure:
Restructuring charge		(12	)		-
Energy and Chemicals:
Barracuda-Caratinga project loss		(407	)		(238	)
Restructuring charge		(28	)		-

In 2004, Iraq-related work contributed approximately $7.1 billion to consolidated revenue and $78 million to consolidated operating income, a 1.1% margin before corporate costs and taxes.

Following is a discussion of our results of operations by reportable segment.

Production Optimization increase in revenue compared to 2003 was largely attributable to production enhancement services, which yielded $430 million in higher revenue. This was driven by a higher average land gas rig count and price increases in the United States, increased activity in Canada and Russia, and increases in pipeline process services and hydraulic workover activity in the United Kingdom. Completion tools and services activities contributed $59 million to the segment revenue increase on improved activity in the Middle East/Asia and Europe/Africa regions. WellDynamics contributed $49 million to segment revenue, driven by the consolidation of the joint venture during the first quarter of 2 004 and increased demand for intelligent well completions services in the Middle East and North America. Prior to 2004, WellDynamics was accounted for under the equity method in the Digital and Consulting Solutions segment. The segment’s improved revenue was partially offset by a significant reduction in sand control and completions activity in Nigeria and a $32 million decline compared to 2003 in revenue from our surface well testing operations sold in the third quarter of 2004. International revenue was 54% of total segment revenue in 2004 compared to 56% in 2003.


	34

The increase in Production Optimization operating income for 2004 compared to 2003 was primarily driven by the higher production enhancement revenues described above, which contributed $155 million. Completion tools and services activities increase of $17 million primarily reflects higher sales of completions and sand control services in the United Kingdom and Norway and a more favorable product mix in Eurasia and Saudi Arabia, offset by a significant reduction in sand control tool sales in Nigeria in the current year. Included in the results were gains of $24 million from the sale of Halliburton Measurement Systems in the second quarter of 2003 and $54 million from the sale of our surface well testing operations in the third and fourth quarters of 2004. Segment results for 2003 also included a $9 million equity l oss from our Subsea 7, Inc. joint venture, largely attributable to changes in estimated project costs and claims recoveries.

Fluid Systems revenue increase in 2004 compared to 2003 was driven by a $177 million improvement in revenue from cementing activities, due primarily to increased land rig count and pricing improvements in the United States and start-up activity on recent contract awards in Mexico and Norway. Drilling fluids contributed $95 million to the segment revenue increase, resulting largely from new land work in Mexico and land rig growth in the United States and Canada. These increases in segment revenue were partially offset by significantly decreased activity in the Gulf of Mexico. International revenue was 58% of total segment revenue in 2004 compared to 56% in 2003.

The Fluid Systems segment operating income increase compared to 2003 resulted from a cementing services increase of $68 million and drilling fluids increase of $22 million. These improved results occurred primarily in the United States due to increased land rig activity, improved pricing, and better utilization and cost management. Partially offsetting improved segment operating income in 2004 was a $17 million impact of reduced higher margin activity in the Gulf of Mexico. Included in 2003 results were equity losses of $7 million from the Enventure expandable casing joint venture, which did not reoccur in 2004. This joint venture is currently accounted for on a cost basis since reducing our ownership in the first quarter of 2004.

Drilling and Formation Evaluation revenue improvement in 2004 compared to 2003 was driven by a $66 million increase in logging and perforating services due to higher land rig activity and pricing improvements in the United States and direct sales to China. Drilling services contributed $40 million to the segment revenue increase, resulting principally from new contracts in Norway and Brazil and higher activity in Canada, Venezuela, and Argentina. The increase in drilling services revenue was partially offset by a substantial decline in logging-while-drilling activity in the Gulf of Mexico. Drill bits sales increased $29 million, benefiting from increases in land rig activity, improved pricing, and b etter market penetration with fixed cutter and roller cone bits primarily in the United States, as well as sales growth in the Caspian Sea region and China. International revenue was 72% of total segment revenue in 2004 and in 2003.

The increase in Drilling and Formation Evaluation segment operating income was due to improved results in drilling services, which benefited from a lower depreciation expense of $35 million in 2004 compared to 2003 primarily due to extending depreciable asset lives in the second quarter of 2004. Logging and perforating services contributed $33 million to the increase, due to improved pricing and land rig activity in the United States and direct sales in China. Drill bits contributed $12 million to improved segment results on higher revenue in the United States and the Caspian Sea region. Operating income for 2003 included a $36 million gain on the disposition of Mono Pumps in the first quarter of 2003.

Digital and Consulting Solutions revenue increased in 2004 compared to 2003 primarily due to a $27 million increase in Landmark Graphics. During 2004, Landmark Graphics achieved its highest revenue since we acquired it. Software-related sales in Landmark Graphics increased in the current year due to strong acceptance of the new real-time (drilling) and GeoProbe offerings. The increase in segment revenue was partially offset by a decline in subsea operations in the first half of 2004 and the absence of $11 million of revenue from Wellstream prior to the sale of this business in the first quarter of 2003. International revenue was 69% of total segment revenue in 2004 compared to 67% in 2003.


	35

Segment operating income increased $75 million from a loss position in 2003. This segment recorded a $77 million charge related to the Anglo-Dutch lawsuit in the third quarter of 2003 and a $15 million loss on the disposition of Wellstream in the first quarter of 2003. For 2004, results were positively impacted by a $13 million release of legal liability accruals in the first quarter of 2004 pertaining to the April 2004 Anglo-Dutch settlement and increased integrated solutions operating income stemming from higher commodity prices. The increase in the segment was partially offset by a $33 million loss recorded in the fourth quarter of 2004 on two integrated solutions projects in Mexico. The loss resulted from operational start-up and subsurface problems on the initial wells, third-party and other cost increases, i ncreased drilling times, and a work stoppage due to community blockage. The charge reflects the estimated total project loss through completion of the drilling program in mid-2006. Segment results for 2004 also included an $11 million charge for an intellectual property settlement.

Government and Infrastructure revenue increased $4.0 billion compared to 2003. The increase was primarily due to $3.7 billion higher revenue from government services contracts in the Middle East. Activities in the DML shipyard projects also contributed $108 million to increased revenue in 2004 compared to 2003.

The Government and Infrastructure operating income decrease resulted from $94 million in write-downs on infrastructure projects in Europe and Africa, a government project in Afghanistan, completion of the construction phase of a rail project in Australia, and reduction in activities in the government project in the Balkans. Current year results were also impacted by a restructuring charge of $12 million due to the reorganization of KBR. The charge related to personnel termination benefits. Partially offsetting the decreases was an increase in income of $14 million from Iraq-related activities primarily due to the LogCAP contract.

Energy and Chemicals decrease in revenue compared to 2003 was primarily due to lower revenue of $1.1 billion on the Barracuda-Caratinga project in Brazil, the Belanak project in Indonesia, completion of refining facilities in the United States, gas projects in Africa, offshore projects in Mexico, and a hydrocarbon project in Europe. The decrease was partially offset by higher revenue of $391 million on refining projects in Canada, an olefins project in the United States, operations and maintenance projects in the United States and the United Kingdom, and new offshore program management projects.

The operating loss for the segment in 2004 primarily resulted from $407 million of losses on the Barracuda-Caratinga project in Brazil, $47 million of losses on a gas project in Africa, and $29 million of losses on the Belanak project in Indonesia. The losses recognized on the Barracuda-Caratinga project were primarily due to the agreement with Petrobras, higher cost estimates, schedule delays, and increased contingencies for the balance of the project until completion. Specifically, in the second quarter, with the integration phase of the Barracuda vessel we experienced a significant reduction in productivity and rework required from the vessel conversion. Also included in the 2004 results was a restructuring charge of $28 million due to the reorganization of KBR. The charge related to personnel termination benef its and asset impairments. Operating losses in 2004 were partially offset by a $59 million increase on an LNG project in Egypt, a refining project in Canada, operations and maintenance projects in the United States and United Kingdom, and new offshore program management projects. The operating loss for 2003 included losses recognized on the Barracuda-Caratinga project of $238 million and losses on a hydrocarbon project in Belgium.

General corporate expenses for 2004 increased primarily due to a $7.5 million charge related to a settlement with the SEC, financing fees on outstanding credit facilities, Sarbanes-Oxley compliance expenses, and increased legal fees.


	36

NONOPERATING ITEMS

Interest expense increased $90 million in 2004 compared to 2003, due primarily to interest on $1.2 billion convertible notes issued in June 2003, $1.05 billion senior floating and fixed notes issued in October 2003, $500 million senior floating-rate notes issued in January 2004, and interest on tax deficiencies in Indonesia and Mexico.

Interest income increased $14 million in 2004 compared to the same period in 2003, attributable to higher average daily cash balances during the year and interest on tax refunds in various jurisdictions.

Loss from discontinued operations, net of tax in 2004 included, on a pretax basis, a $778 million charge for the revaluation of 59.5 million shares of Halliburton common stock to be contributed to the asbestos claimant trust as part of the proposed settlement, a $698 million charge related to the write-down of the asbestos and silica insurance receivable, a $44 million charge related to our October 2004 partitioning agreement, and an $11 million charge related to the delayed-draw term facility, which expired in June 2004. The remaining amount primarily consisted of professional and administrative fees related to various aspects of the proposed asbestos and silica settlement, accretion on the asbesto s insurance receivables, and our October 2004 partitioning agreement. The loss from discontinued operations was $1.145 billion in 2003. The benefit for income taxes on discontinued operations was $180 million in 2004, compared to a provision of $6 million for 2003. We have established a valuation allowance against the deferred tax asset arising from the asbestos and silica charges to reflect the expected net tax benefit from the future deductions the charges will create. In 2004, we increased the valuation allowance by $449 million to a balance of $1.073 billion. The balance at the end of 2003 was $624 million.

Cumulative effect of change in accounting principle, net for the year ended 2003 was an $8 million after-tax charge, or $0.02 per diluted share, related to our January 1, 2003 adoption of Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 addresses the financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated assets’ retirement costs. The asset retirement obligations primarily relate to the removal of leasehold improvements upon exiting certain lease arrangements and restoration of land associated with the mining of bentonite.


	37

RESULTS OF OPERATIONS IN 2003 COMPARED TO 2002

*REVENUE*:					Increase/			Percentage
Millions of dollars	2003		2002		(Decrease)			Change
Production Optimization	$	2,758	$	2,544	$	214			8	%
Fluid Systems		2,039		1,815		224			12
Drilling and Formation Evaluation		1,643		1,633		10			1
Digital and Consulting Solutions		555		844		(289	)		(34	)
Total Energy Services Group		6,995		6,836		159			2
Government and Infrastructure		5,417		1,539		3,878			252
Energy and Chemicals		3,859		4,197		(338	)		(8	)
Total KBR		9,276		5,736		3,540			62
Total revenue	$	16,271	$	12,572	$	3,699			29	%

Geographic - Energy Services Group segments only:
Production Optimization:
North America	$	1,337	$	1,254	$	83			7	%
Latin America		317		277		40			14
Europe/Africa		562		556		6			1
Middle East/Asia		542		457		85			19
Subtotal		2,758		2,544		214			8
Fluid Systems:
North America		990		934		56			6
Latin America		258		216		42			19
Europe/Africa		452		381		71			19
Middle East/Asia		339		284		55			19
Subtotal		2,039		1,815		224			12
Drilling and Formation Evaluation:
North America		558		549		9			2
Latin America		261		251		10			4
Europe/Africa		312		344		(32	)		(9	)
Middle East/Asia		512		489		23			5
Subtotal		1,643		1,633		10			1
Digital and Consulting Solutions:
North America		200		294		(94	)		(32	)
Latin America		71		102		(31	)		(30	)
Europe/Africa		116		297		(181	)		(61	)
Middle East/Asia		168		151		17			11
Subtotal		555		844		(289	)		(34	)
Total Energy Services Group
revenue by region:
North America		3,085		3,031		54			2
Latin America		907		846		61			7
Europe/Africa		1,442		1,578		(136	)		(9	)
Middle East/Asia		1,561		1,381		180			13
Total Energy Services Group
revenue	$	6,995	$	6,836	$	159			2	%


	38

*OPERATING INCOME (LOSS):*							Increase/			Percentage
Millions of dollars	2003			2002			(Decrease)			Change
Production Optimization	$	413		$	374		$	39			10	%
Fluid Systems		251			202			49			24
Drilling and Formation Evaluation		177			160			17			11
Digital and Consulting Solutions		(15	)		(98	)		83			85
Total Energy Services Group		826			638			188			29
Government and Infrastructure		194			75			119			159
Energy and Chemicals		(225	)		(131	)		(94	)		(72	)
Shared KBR		(5	)		(629	)		624			99
Total KBR		(36	)		(685	)		649			95
General corporate		(70	)		(65	)		(5	)		(8	)
Operating income (loss)	$	720		$	(112	)	$	832			NM

Geographic - Energy Services Group segments only:
Production Optimization:
North America	$	194		$	218		$	(24	)		(11	)%
Latin America		75			41			34			83
Europe/Africa		52			46			6			13
Middle East/Asia		92			69			23			33
Subtotal		413			374			39			10
Fluid Systems:
North America		104			119			(15	)		(13	)
Latin America		52			33			19			58
Europe/Africa		48			20			28			140
Middle East/Asia		47			30			17			57
Subtotal		251			202			49			24
Drilling and Formation Evaluation:
North America		60			70			(10	)		(14	)
Latin America		30			29			1			3
Europe/Africa		30			(6	)		36			NM
Middle East/Asia		57			67			(10	)		(15	)
Subtotal		177			160			17			11
Digital and Consulting Solutions:
North America		(52	)		(208	)		156			75
Latin America		8			5			3			60
Europe/Africa		17			118			(101	)		(86	)
Middle East/Asia		12			(13	)		25			192
Subtotal		(15	)		(98	)		83			85
Total Energy Services Group
operating income by region:
North America		306			199			107			54
Latin America		165			108			57			53
Europe/Africa		147			178			(31	)		(17	)
Middle East/Asia		208			153			55			36
Total Energy Services Group
operating income	$	826		$	638		$	188			29	%

NM - Not Meaningful


	39

The increase in consolidated revenue for 2003 compared to 2002 was largely attributable to activity in our government services projects, primarily work in the Middle East. International revenue was 73% of total revenue in 2003 and 67% of total revenue in 2002, with the increase attributable to our government services projects. During 2003, the United States Government became a major customer of ours with total revenue of approximately $4.2 billion or 26% of consolidated revenue for 2003. Revenue from the United States Government during 2002 represented less than 10% of consolidated revenue. The consolidated operating income increase in 2003 compared to 2002 was largely attributable to our government services projects and the absence of the $644 million in asbestos and silica charges and restructuring charges that occurred in 2002. In addition, we recorded a loss on the Barracuda-Caratinga project of $238 million in 2003 as compared to a $117 million loss in 2002. Our Energy Services Group segments accounted for approximately $188 million of the increase in income.

The table below provides significant items included in segment operating income.

	Years ended December 31
Millions of dollars	2003			2002
Production Optimization:
HMS gain on sale	$	24		$	-
Drilling and Formation Evaluation:
Mono Pumps gain on sale		36			-
Digital and Consulting Solutions:
Anglo-Dutch lawsuit		(77	)		-
Wellstream loss on sale		(15	)		-
EMC gain on sale		-			108
Patent infringement lawsuit accrual		-			(98	)
Restructuring charge		-			(64	)
Bredero-Shaw impairment		-			(61	)
Bredero-Shaw loss on sale		-			(18	)
Government and Infrastructure:
Restructuring charge		-			(5	)
Energy and Chemicals:
Barracuda-Caratinga project loss		(238	)		(117	)
Restructuring charge		-			(13	)
Shared KBR:
Asbestos and silica liability accruals		(5	)		(564	)
Highlands receivable write-off		-			(80	)
General corporate:
Insurance company demutualization		-			29
Restructuring charge		-			(25	)

In 2003, Iraq-related work contributed approximately $3.6 billion to consolidated revenue and $85 million to consolidated operating income, a 2.4% margin before corporate costs and taxes.

Following is a discussion of our results of operations by reportable segment.

Production Optimization increase in revenue was mainly attributable to production enhancement services, which increased $187 million compared to 2002, driven by higher activity in the Middle East following the end of the war in Iraq and increased rig count in Mexico and North America. In addition, completion tools and services activities increased $35 million compared to 2002 due primarily to increased land rig counts in North America, increased activity in Brazil due to higher activity with national and international oil companies in deepwater, and increased rig activity in Mexico. These increases were partially offset by lower activity in the Gulf of Mexico and the United Kingdom. The May 2003 sal e of Halliburton Measurement Systems had a $24 million negative impact on segment revenue in 2003 compared to


	40

2002. The improvement in revenue more than offset the $9 million in equity losses from the Subsea 7, Inc. joint venture. International revenue was 56% of segment revenue in 2003 compared to 53% in 2002 as activity picked up in the Middle East following the end of the war in Iraq.

The Production Optimization operating income increase included a $24 million gain on the sale of Halliburton Measurement Systems in North America, offset by inventory write-downs.

Fluid Systems increase in revenue was driven by drilling fluids sales increase of $101 million and cementing activities increase of $121 million compared to 2002. Cementing benefited from higher land rig counts in the United States. Both drilling fluids and cementing revenue benefited from increased activity in Mexico, primarily with PEMEX, which offset lower activity in Venezuela. Drilling fluids also benefited from price improvements on certain contracts in Europe/Africa. International revenue was 56% of total revenue in 2003 compared to 52% in 2002.

The Fluid Systems segment operating income increase was a result of drilling fluids increasing $29 million and cementing services increasing $24 million compared to 2002, partially offset by lower results of $4 million from Enventure. Drilling fluids benefited from higher sales of biodegradable drilling fluids and improved contract terms. Those benefits were partially offset by contract losses in the Gulf of Mexico and United States pricing pressures in 2003. Cementing operating income primarily increased in Middle East/Asia due to collections on previously reserved receivables, certain start-up costs in 2002, and higher margin work. All regions showed improved segment operating income in 2003 compared to 2002, except North America, which was impacted by the decrease in activity from the higher margin offshore bus iness in the Gulf of Mexico.

Drilling and Formation Evaluation revenue was essentially flat. Logging and perforating services revenue increased $25 million, primarily due to higher average year-over-year rig counts in the United States and Mexico, partially offset by lower sales in China and reduced activity in Venezuela. Drill bits revenue increased $21 million, benefiting from the increased rig counts in the United States and Canada. Drilling services revenue for 2003 was negatively impacted by $79 million compared to 2002 due to the sale of Mono Pumps in January 2003. The remainder of drilling services revenue increased $34 million compared to 2002 as contracts that were expiring were more than offset by new contracts, prima rily in West Africa, the Middle East and Ecuador. Also impacting drilling services were significant price discounts in the fourth quarter of 2003 on basic drilling services and rotary steerables in the United Kingdom. International revenue was 72% of total segment revenue in both 2003 and 2002.

The increase in operating income for the segment was primarily driven by logging and perforating services, which increased operating income by $32 million, a result of increased rig counts internationally, lower discounts in the United States and the absence of start-up costs incurred in 2002. Operating income for 2003 also included a $36 million gain ($24 million in North America and $12 million in Europe/Africa) on the sale of Mono Pumps. Operating income for drilling services decreased by $49 million and $9 million for drill bits compared to 2002 due to lower activity in Venezuela, pricing pressures in the United States, severance expense, and facility consolidation expenses. Drilling services operating income for 2003 was negatively impacted by $5 million compared to 2002 due to the sale of Mono Pumps.< /DIV>

Digital and Consulting Solutions decrease in revenue compared to 2002 was primarily due to the contribution of most of the assets of Halliburton Subsea to Subsea 7, Inc., which beginning in May 2002 was reported on the equity basis. This accounted for approximately $200 million of the decrease. The sale of Wellstream in March 2003 also contributed $49 million to the decrease. Revenue for Landmark Graphics was down $13 million compared to 2002 due to the general weakness in information technology spending. International revenue was 67% of segment revenue in 2003 compared to 74% in 2002. The decrease is the result of the contribution of the Halliburton Subsea assets to Subsea 7, Inc., which mainly con ducts operations in the North Sea.


	41

Segment operating loss was $15 million in 2003 compared to a loss of $98 million in 2002. Included in 2003 were a $15 million loss on the sale of Wellstream ($11 million in North America and $4 million in Europe/Africa) and a $77 million charge related to the October 2003 verdict in the Anglo-Dutch lawsuit, which impacted North America results. The significant items affecting operating income in 2002 included:

$108 million gain on the sale of European Marine Contractors Ltd. in Europe/Africa;

$98 million charge for BJ Services patent infringement lawsuit accrual in North America;

$79 million loss on the impairment of our 50% equity investment in the Bredero-Shaw joint venture in North America; and

$64 million in expense related to restructuring charges ($51 million in North America, $3 million in Latin America, $7 million in Europe/Africa, and $3 million in Middle East/Asia).

Government and Infrastructure increase in revenue compared to 2002 was due to increased activity in Iraq for the United States government, and, to a lesser extent, a $264 million increase on other government projects.

Government and Infrastructure operating income improvement in 2003 was due to government-related activities, partially stemming from operations in the Middle East for Iraq-related work and a $14 million increase in income from other government projects.

Energy and Chemicals decrease in revenue compared to 2002 was due to lower revenue earned on the Barracuda-Caratinga project in Brazil and a $111 million decrease on industrial services projects in the United States and production services projects globally. Partially offsetting the revenue decrease was a $161 million increase on LNG and oil and gas projects in Africa.

The operating loss for the segment was $225 million in 2003 compared to an operating loss of $131 million in 2002. The operating loss in 2003 included losses recognized on the Barracuda-Caratinga project of $238 million and losses on a hydrocarbon project in Belgium. Partially offsetting these losses were income from liquefied natural gas projects in Africa. Included in the 2002 results were a loss on the Barracuda-Caratinga project of $117 million and $13 million of restructuring charges.

Shared KBR in 2002 included a charge of $564 million related to the asbestos- and silica-related liabilities and a charge of $80 million to write-off our receivable from Highlands Insurance Company to cover asbestos claims (see Note 11 to our consolidated financial statements).

General corporate in 2002 included a $29 million pretax gain for the value of stock received from the demutualization of an insurance provider, partially offset by 2002 restructuring charges of $25 million. The higher 2003 expenses also relate to preparations for the certifications required under Section 404 of the Sarbanes-Oxley Act.

NONOPERATING ITEMS

Interest expense increased $26 million in 2003 compared to 2002. The increase was due primarily to $30 million in interest on the $1.2 billion convertible notes issued in June 2003 and the $1.05 billion senior floating and fixed notes issued in October 2003. The increase was partially offset by $5 million in pre-judgment interest recorded in 2002 related to the BJ Services patent infringement judgment and $296 million of scheduled debt repayments in 2003.

Foreign currency losses, net for 2003 included gains in Canada offset by losses in the United Kingdom and Brazil. Losses in 2002 were due to negative developments in Brazil, Argentina, and Venezuela.

Provision for income taxes of $234 million resulted in an effective tax rate on continuing operations of 38.2% in 2003. The provision was $80 million in 2002 on a net loss from continuing operations. The inclusion of asbestos accruals in continuing operations for 2002 was the primary cause of the unusual 2002 effective tax rate on continuing operations. There are no asbestos charges or related tax accruals included in continuing operations for 2003. Our impairment loss on


	42

Bredero-Shaw during 2002 could not be benefited for tax purposes due to book and tax basis differences in that investment and the limited benefit generated by a capital loss carryback. However, due to changes in circumstances regarding prior years, we are now able to carry back a portion of the capital loss, which resulted in an $11 million benefit in 2003.

Loss from discontinued operations, net of tax of $1.2 billion in 2003 was due to the following:

asbestos and silica liability was increased to reflect the full amount of the proposed settlement as a result of the Chapter 11 proceeding;

charges related to our July 2003 funding of $30 million for the debtor-in-possession financing to Harbison-Walker in connection with its Chapter 11 proceedings that was expected to be forgiven by Halliburton on the earlier of the effective date of a plan of reorganization for DII Industries or the effective date of a plan of reorganization for Harbison-Walker acceptable to DII Industries;

$10 million allowance for an estimated portion of uncollectible amounts related to the insurance receivables purchased from Harbison-Walker;

professional fees associated with the due diligence, printing, and distribution cost of the disclosure statement and other aspects of the proposed settlement for asbestos and silica liabilities; and

a release of environmental and legal reserves related to indemnities that were part of our disposition of the Dresser Equipment Group and were no longer needed.

The loss of $652 million in 2002 was due primarily to charges recorded for asbestos and silica liabilities and a $40 million payment associated with the Harbison-Walker Chapter 11 filing.

The provision for income taxes on discontinued operations was $6 million in 2003 compared to a tax benefit of $154 million in 2002. We have established a valuation allowance against the deferred tax asset arising from the asbestos and silica charges to reflect the expected net tax benefit from the future deductions the charges will create. In 2003, we increased the valuation allowance by $391 million to a balance of $624 million. The balance at the end of 2002 was $233 million.

Cumulative effect of change in accounting principle, net was an $8 million after-tax charge, or $0.02 per diluted share, related to our January 1, 2003 adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 addresses the financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated assets’ retirement costs. The asset retirement obligations primarily relate to the removal of leasehold improvements upon exiting certain lease arrangements and restoration of land associated with the mining of bentonite.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies are described below to provide a better understanding of how we develop our judgments about future events and related estimations and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective, or complex estimates and assessments and is fundamental to our results of operations. We identified our most critical accounting estimates to be:

percentage-of-completion accounting for contracts to provide construction, engineering, design, or similar services;

accounting for government contracts;

allowance for bad debts;

forecasting our effective tax rate, including our future ability to utilize foreign tax credits and the realizability of deferred tax assets; and

legal and investigation matters.


	43

We base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We believe the following are the critical accounting policies used in the preparation of our consolidated financial statements, as well as the significant estimates and judgments affecting the application of these policies. This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in this report.

We have discussed the development and selection of these critical accounting policies and estimates with the Audit Committee of our Board of Directors, and the Audit Committee has reviewed the disclosure presented below.

Percentage of completion

Revenue from contracts to provide construction, engineering, design or similar services, almost all of which relates to KBR, is reported on the percentage-of-completion method of accounting. This method of accounting requires us to calculate job profit to be recognized in each reporting period for each job based upon our predictions of future outcomes, which include:

estimates of the total cost to complete the project;

estimates of project schedule and completion date;

estimates of the percentage the project is complete; and

amounts of any probable unapproved claims and change orders included in revenue.

At the outset of each contract, we prepare a detailed analysis of our estimated cost to complete the project. Risks relating to service delivery, usage, productivity, and other factors are considered in the estimation process. Our project personnel periodically evaluate the estimated costs, claims, change orders, and percentage of completion at the project level. The recording of profits and losses on long-term contracts requires an estimate of the total profit or loss over the life of each contract. This estimate requires consideration of contract revenue, change orders, and claims, less costs incurred and estimated costs to complete. Anticipated losses on contracts are recorded in full in the period in which they become evident. Profits are recorded based upon the total estimated contract profit times the curren t percentage complete for the contract.

When calculating the amount of total profit or loss on a long-term contract, we include unapproved claims as revenue when the collection is deemed probable based upon the four criteria for recognizing unapproved claims under the American Institute of Certified Public Accountants Statement of Position 81-1 (SOP 81-1), “Accounting for Performance of Construction-Type and Certain Production-Type Contracts.” Including probable unapproved claims in this calculation increases the operating income (or reduces the operating loss) that would otherwise be recorded without consideration of the probable unapproved claims. Probable unapproved claims are recorded to the extent of costs incurred and include no profit element. In all cases, the probable unapproved claims included in determining contract profit or loss a re less than the actual claim that will be or has been presented to the customer. We are actively engaged in claims negotiations with our customers, and the success of claims negotiations have a direct impact on the profit or loss recorded for any related long-term contract. Unsuccessful claims negotiations could result in decreases in estimated contract profits or additional contract losses, and successful claims negotiations could result in increases in estimated contract profits or recovery of previously recorded contract losses.

At least quarterly, significant projects are reviewed in detail by senior management. We have a long history of dealing with multiple types of projects and in preparing cost estimates. However, there are many factors that impact future costs, including but not limited to weather, inflation, labor and community disruptions, timely availability of materials, productivity, and other factors as outlined in our “Forward-Looking Information and Risk Factors.” These factors can affect the accuracy of our estimates and materially impact our future reported earnings. In the past, we have incurred substantial losses on projects that were not initially projected, including our Barracuda-Caratinga project (see “Barracuda-Caratinga Project” for further discussion).


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Accounting for government contracts

Most of the services provided to the United States government are governed by cost-reimbursable contracts. Services under our LogCAP, RIO, PCO Oil South, and Balkans support contracts are examples of these types of arrangements. Generally, these contracts contain both a base fee (a fixed profit percentage applied to our actual costs to complete the work) and an award fee (a variable profit percentage applied to definitized costs, which is subject to our customer’s discretion and tied to the specific performance measures defined in the contract, such as adherence to schedule, health and safety, quality of work, responsiveness, cost performance, and business management).

Base fee revenue is recorded at the time services are performed, based upon actual project costs incurred, and include a reimbursement fee for general, administrative, and overhead costs. The general, administrative, and overhead cost reimbursement fees are estimated periodically in accordance with government contract accounting regulations and may change based on actual costs incurred or based upon the volume of work performed. Revenue may be reduced for our estimate of costs that may be categorized as disputed or unallowable as a result of cost overruns or the audit process.

Award fees are generally evaluated and granted periodically by our customer. For contracts entered into prior to June 30, 2003, award fees are recognized during the term of the contract based on our estimate of amounts to be awarded. Once award fees are granted and task orders underlying the work are definitized, we adjust our estimate of award fees to actual amounts earned. Our estimates are often based on our past award experience for similar types of work. We have been receiving award fees on the Balkans project since 1995, and our estimates for award fees for this project have generally been accurate in the periods presented. We are in the initial stages of the award fees process for the RIO and LogCAP projects and, therefore, these estimates are made with less history, and the controversial nature of these co ntracts may cause actual awards to vary significantly from past experience.

As a result of our adoption of Emerging Issues Task Force Issue No. 00-21 (EITF 00-21), “Revenue Arrangements with Multiple Deliverables,” for contracts entered into subsequent to June 30, 2003 (such as PCO Oil South), we do not recognize award fees for contracts containing multiple deliverables based on estimates. Instead, they are recognized only when definitized and awarded by the customer. Also, for service-only contracts, award fees are recognized only when awarded by the customer. Award fees on government construction contracts are recognized during the term of the contract based on our estimate of the amount of fees to be awarded.

Similar to many cost-reimbursable contracts, these government contracts are typically subject to audit and adjustment by our customer. Each contract is unique; therefore, the level of confidence in our estimates for audit adjustments varies depending on how much historical data we have with a particular contract. Further, the significant size and controversial nature of the RIO and LogCAP contracts may cause actual awards to vary significantly from past experience.

The estimates employed in our accounting for government contracts affect our Government and Infrastructure segment.

Allowance for bad debts

We evaluate our accounts receivable through a continuous process of assessing our portfolio on an individual customer and overall basis. This process consists of a thorough review of historical collection experience, current aging status of the customer accounts, financial condition of our customers, and other factors such as whether the receivables involve retentions or billing disputes. We also consider the economic environment of our customers, both from a marketplace and geographic perspective, in evaluating the need for an allowance. Based on our review of these factors, we establish or adjust allowances for specific customers and the accounts receivable portfolio as a whole. This process involves a high degree of judgment and estimation, and frequently involves significant dollar amounts. Accordingly, our re sults of operations can be affected by adjustments to the allowance due to actual write-offs that differ from estimated amounts. Our estimates of allowances for bad debts have historically been accurate. Over the last five years, our estimates of


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allowances for bad debts, as a percentage of notes and accounts receivable before the allowance, have ranged from 4.0% to 6.0%. At December 31, 2004, allowance for bad debts totaled $127 million or 4.3% of notes and accounts receivable before the allowance, and at December 31, 2003, allowance for bad debts totaled $175 million or 5.7% of notes and accounts receivable before the allowance. A 1% change in our estimate of the collectibility of our notes and accounts receivable balance as of December 31, 2004 would have resulted in a $30 million adjustment to 2004 total operating costs and expenses.

Income tax accounting

We account for our income taxes in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes,” which requires the recognition of the amount of taxes payable or refundable for the current year and an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been recognized in our financial statements or tax returns. We apply the following basic principles in accounting for our income taxes:

a current tax liability or asset is recognized for the estimated taxes payable or refundable on tax returns for the current year;

a deferred tax liability or asset is recognized for the estimated future tax effects attributable to temporary differences and carryforwards;

the measurement of current and deferred tax liabilities and assets is based on provisions of the enacted tax law, and the effects of potential future changes in tax laws or rates are not considered; and

the value of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that, based on available evidence, are not expected to be realized.

We determine deferred taxes separately for each tax-paying component (an entity or a group of entities that is consolidated for tax purposes) in each tax jurisdiction. That determination includes the following procedures:

identifying the types and amounts of existing temporary differences;

measuring the total deferred tax liability for taxable temporary differences using the applicable tax rate;

measuring the total deferred tax asset for deductible temporary differences and operating loss carryforwards using the applicable tax rate;

measuring the deferred tax assets for each type of tax credit carryforward; and

reducing the deferred tax assets by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Our methodology for recording income taxes requires a significant amount of judgment in the use of assumptions and estimates. Additionally, we use forecasts of certain tax elements such as taxable income and foreign tax credit utilization, as well as evaluate the feasibility of implementing tax planning strategies. Given the inherent uncertainty involved with the use of such variables, there can be significant variation between anticipated and actual results. Unforeseen events may significantly impact these variables, and changes to these variables could have a material impact on our income tax accounts related to both continuing and discontinued operations.

We have operations in more than 100 countries other than the United States. Consequently, we are subject to the jurisdiction of a significant number of taxing authorities. The income earned in these various jurisdictions is taxed on differing bases, including income actually earned, income deemed earned, and revenue-based tax withholding. The final determination of our tax liabilities involves the interpretation of local tax laws, tax treaties, and related authorities in each jurisdiction. Changes in the operating environment, including changes in tax law and currency/repatriation controls, could impact the determination of our tax liabilities for a tax year.


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Tax filings of our subsidiaries, unconsolidated affiliates, and related entities are routinely examined in the normal course of business by tax authorities. These examinations may result in assessments of additional taxes, which we work to resolve with the tax authorities or through the judicial process. Predicting the outcome of disputed assessments involves some uncertainty. Factors such as the availability of settlement procedures, willingness of tax authorities to negotiate, and the operation and impartiality of judicial systems vary across the different tax jurisdictions and may significantly influence the ultimate outcome. We review the facts for each assessment, then utilize assumptions and estimates to determine the most likely outcome and provide taxes based on this outcome.

We have recorded a valuation allowance on the asbestos and silica liabilities based on the anticipated impact of the future asbestos and silica deductions on our ability to utilize future foreign tax credits in the United States. This valuation allowance is determined quarterly based on a number of estimates including future creditable foreign taxes, tax loss carryforwards that the deductions will generate, and future taxable income. Factors such as actual operating results, material acquisitions or dispositions, and changes to our operating environment could alter the estimates, and such changes could have a material impact on the valuation allowance.

Legal and investigation matters

We are currently involved in other legal proceedings and investigations not involving asbestos and silica. As discussed in Note 13 of our consolidated financial statements, as of December 31, 2004, we have accrued an estimate of the probable and estimable costs for the resolution of some of these matters. For other matters for which the liability is not probable and reasonably estimable, we have not accrued any amounts. Attorneys in our legal department monitor and manage all claims filed against us and review all pending investigations. Generally, the estimate of probable costs related to these matters is developed in consultation with outside legal counsel representing us. Our estimates are based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. The precision of these estimates is impacted by the amount of due diligence we have been able to perform. We attempt to resolve these matters through settlements, mediation, and arbitration proceedings when possible. If the actual settlement costs, final judgments, or fines, after appeals, differ from our estimates, our future financial results may be adversely affected. We have in the past recorded significant adjustments to our initial estimates of these types of contingencies.

OFF BALANCE SHEET RISK

On April 15, 2002, we entered into an agreement to sell eligible United States Energy Services Group accounts receivable to a bankruptcy-remote limited-purpose funding subsidiary. Under the terms of the agreement, new receivables are added on a continuous basis to the pool of receivables. Collections reduce previously sold accounts receivable. This funding subsidiary sells an undivided ownership interest in this pool of receivables to entities managed by unaffiliated financial institutions under another agreement. Sales to the funding subsidiary have been structured as “true sales” under applicable bankruptcy laws. While the funding subsidiary is wholly owned by us, its assets are not available to pay any creditors of ours or of our subsidiaries or affiliates. The undivided ownership interest in the pool of receivables sold to the unaffiliated companies, therefore, is reflected as a reduction of accounts receivable in our consolidated balance sheets. The funding subsidiary retains the interest in the pool of receivables that are not sold to the unaffiliated companies and is fully consolidated and reported in our financial statements.

The amount of undivided interests that can be sold under the program varies based on the amount of eligible Energy Services Group receivables in the pool at any given time and other factors. In April 2004, the expiration date for our Energy Services Group accounts receivable securitization facility was extended to April 2005. The maximum amount that


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may be sold and outstanding under this agreement at any given time is $300 million. As of December 31, 2004, we had sold $256 million undivided ownership interest to unaffiliated companies.

In May 2004, we entered into an agreement to sell, assign, and transfer the entire title and interest in specified United States government accounts receivable of KBR to a third party. The face value of the receivables sold to the third party is reflected as a reduction of accounts receivable in our consolidated balance sheets. The amount of receivables that can be sold under the agreement varies based on the amount of eligible receivables at any given time and other factors, and the maximum amount that may be sold and outstanding under this agreement at any given time is $650 million. The total amount of receivables outstanding under this agreement as of December 31, 2004 was approximately $263 million. Subsequent to December 31, 2004, these receivables were collected and the balance retired, and we are not curre ntly selling receivables, although the facility continues to be available.

We have exposure to losses in certain unconsolidated variable interest entities. See Note 20 to the consolidated financial statements for more information.

FINANCIAL INSTRUMENT MARKET RISK

We are exposed to financial instrument market risk from changes in foreign currency exchange rates, interest rates, and, to a limited extent, commodity prices. We selectively manage these exposures through the use of derivative instruments to mitigate our market risk from these exposures. The objective of our risk management program is to protect our cash flows related to sales or purchases of goods or services from market fluctuations in currency rates. We do not use derivative instruments for trading purposes. Our use of derivative instruments includes the following types of market risk:

volatility of the currency rates;

time horizon of the derivative instruments;

market cycles; and

the type of derivative instruments used.

We do not consider any of these risk management activities to be material. See Note 1 to the consolidated financial statements for additional information on our accounting policies on derivative instruments. See Note 18 to the consolidated financial statements for additional disclosures related to derivative instruments.

Interest rate risk. We have exposure to interest rate risk from our long-term debt.

The following table represents principal amounts of our long-term debt at December 31, 2004 and related weighted average interest rates by year of maturity for our long-term debt.

Millions of dollars	2005			2006			2007			2008			2009		Thereafter			Total
Fixed-rate debt:
Amount ($US)	$	1		$	280		$	-		$	150		$	-	$	2,625		$	3,056
Weighted average
interest rate		6.9	%		6.0	%		-			5.6	%		-		5.0	%		5.1	%
Variable-rate debt:
Amount ($US)	$	346		$	18		$	518		$	6		$	-	$	-		$	888
Weighted average
interest rate		3.8	%		5.4	%		3.0	%		5.5	%		-		-			3.4	%

The fair market value of long-term debt was $3.7 billion as of December 31, 2004.


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ENVIRONMENTAL MATTERS

We are subject to numerous environmental, legal, and regulatory requirements related to our operations worldwide. In the United States, these laws and regulations include, among others:

the Comprehensive Environmental Response, Compensation, and Liability Act;

the Resources Conservation and Recovery Act;

the Clean Air Act;

the Federal Water Pollution Control Act; and

the Toxic Substances Control Act.

We do not expect costs related to these remediation requirements to have a material adverse effect on our consolidated financial position or our results of operations. Our accrued liabilities for environmental matters were $41 million as of December 31, 2004 and $31 million as of December 31, 2003. The liability covers numerous properties and no individual property accounts for more than $5 million of the liability balance. We have subsidiaries that have been named as potentially responsible parties along with other third parties for 15 federal and state superfund sites for which we have established a liability. As of December 31, 2004, those 15 sites accounted for approximately $11 million of our total $41 million liability. In some instances, we have been named a potentially responsible party by a regulatory age ncy, but in each of those cases, we do not believe we have any material liability.

NEW ACCOUNTING PRONOUNCEMENTS

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R, “Share-Based Payment.” We will adopt the provisions of SFAS No. 123R on July 1, 2005 using the modified prospective application. Accordingly, we will recognize compensation expense for all newly granted awards and awards modified, repurchased, or cancelled after July 1, 2005. Compensation cost for the unvested portion of awards that are outstanding as of July 1, 2005 will be recognized ratably over the remaining vesting period. The compensation cost for the unvested portion of awards will be based on the fair value at date of grant as calculated for our pro forma disclosure under SFAS No. 123. We will recognize compensation expense for our Employee Stock Purchase Program beginning with the July 1, 2005 purchase period .

We estimate that the effect on net income and earnings per share in the periods following adoption of SFAS No. 123R will be consistent with our pro forma disclosure under SFAS No. 123, except that estimated forfeitures will be considered in the calculation of compensation expense under SFAS No. 123R. However, the actual effect on net income and earnings per share will vary depending upon the number of options granted in 2005 compared to prior years and the number of shares purchased under the Employee Stock Purchase Plan. Further, we have not yet determined the actual model we will use to calculate fair value.


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FORWARD-LOOKING INFORMATION AND RISK FACTORS

The Private Securities Litigation Reform Act of 1995 provides safe harbor provisions for forward-looking information. Forward-looking information is based on projections and estimates, not historical information. Some statements in this Form 10-K are forward-looking and use words like “may,” “may not,” “believes,” “do not believe,” “expects,” “do not expect,” “anticipates,” “do not anticipate,” and other expressions. We may also provide oral or written forward-looking information in other materials we release to the public. Forward-looking information involves risks and uncertainties and reflects our best judgment based on current information. Our results of operations can be affected by inaccurate assumptions we make or by known or un known risks and uncertainties. In addition, other factors may affect the accuracy of our forward-looking information. As a result, no forward-looking information can be guaranteed. Actual events and the results of operations may vary materially.

We do not assume any responsibility to publicly update any of our forward-looking statements regardless of whether factors change as a result of new information, future events, or for any other reason. You should review any additional disclosures we make in our press releases and Forms 10-Q and 8-K filed with the SEC. We also suggest that you listen to our quarterly earnings release conference calls with financial analysts.

While it is not possible to identify all factors, we continue to face many risks and uncertainties that could cause actual results to differ from our forward-looking statements and potentially materially and adversely affect our financial condition and results of operations, including risks relating to:

Legal Matters

United States Government contract work

We provide substantial work under our government contracts business to the United States Department of Defense and other governmental agencies, including worldwide United States Army logistics contracts, known as LogCAP, and contracts to rebuild Iraq’s petroleum industry, known as RIO and PCO Oil South. Our government services revenue related to Iraq totaled approximately $7.1 billion in 2004. Most of the services provided to the United States government are subject to cost-reimbursable contracts where we have the opportunity to earn an award fee based on our customer’s evaluation of the quality of our performance. These award fees are evaluated and granted by our customer periodically. For the LogCAP and RIO contracts, we recognize award fees based on our estimate of amounts to be awarded. In determinin g our estimates, we consider, among other things, past award experience for similar types of work. These estimates are adjusted to actual when the task orders are definitized and the award fees have been finalized by our customer.


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Dining Facility and Administration Centers (DFACs). During 2003, the DCAA raised issues relating to our invoicing to the Army Materiel Command (AMC) for food services for soldiers and supporting civilian personnel in Iraq and Kuwait. We believe the issues raised by the DCAA relate to the difference between the number of troops the AMC directed us to support and the number of soldiers counted at dining facilities for United States troops and supporting civilian personnel. In the first quarter of 2004, we reviewed our DFAC subcontracts in our Iraq and Kuwait areas of operation and have billed and continue to bill for all current DFAC costs. During 2004, we received notice from the DCAA that it


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was recommending withholding a portion of our DFAC billings. For DFAC billings relating to subcontracts entered into prior to February 2004, the DCAA has recommended withholding 19.35% of the billings until it completes its audits. Subsequent to February 2004, we renegotiated our DFAC subcontracts to address the specific issues raised by the DCAA and advised the AMC and the DCAA of the new terms of the arrangements. We have had no objection by the government to the terms and conditions associated with these new DFAC subcontract agreements. During the third quarter of 2004, we received notification that, for three Kuwait DFACs, the DCAA recommended to our customer that costs be disallowed because the DCAA is not satisfied with the level of documentation provided by us. The amount withheld related to suspended and re commended disallowed DFAC costs for work performed prior to February 2004 and totaled approximately $224 million as of December 31, 2004. The amount withheld could change as the DCAA continues their audits of the remaining DFAC facilities. We are negotiating with our customer, the AMC, to resolve this issue. We are currently withholding a proportionate amount of these billings from our subcontractors.

Withholding of payments. During 2004, the AMC issued a determination that a particular contract clause could cause it to withhold 15% from our invoices until our task orders under the LogCAP contract are definitized. The AMC delayed implementation of this withholding pending further review. The Army Field Support Command (AFSC) has now been delegated authority by the AMC to determine whether or not to implement the withholding. The AFSC has informed us that it will assess the situation on a task order by task order basis and, currently, withholding will continue to be delayed. We do not believe any potential 15% withholding will have a significant or sustained impact on our liquidity because any withholding is tempo rary and ends once the definitization process is complete. During the third quarter of 2004, we and the AMC identified three senior management teams to facilitate negotiation under the LogCAP task orders, and these teams are working to negotiate outstanding issues and definitize task orders as quickly as possible. We are continuing to work with our customer to resolve outstanding issues. As of January 18, 2005, 25 task orders for LogCAP totaling over $636 million have been definitized.


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We are working diligently with our customers to proceed with significant new work only after we have a fully definitized task order, which should limit withholdings on future task orders.

Cost reporting. We have received notice that a contracting officer for our PCO Oil South project considers our monthly categorization and detail of costs and our ability to schedule and forecast costs to be inadequate, and he has requested corrections be made by March 10, 2005. We expect to be able to make the requested corrections. If we were unable to satisfy our customer, our customer may pursue remedies under the applicable federal acquisition regulations, including terminating the affected contract. Although there can be no assurances, we do not expect that our work on the PCO Oil South project will be terminated for default. We are in the process of developing an acceptable management cost reporting system and are supplementing the existing PCO cost reporting team with additional manpower.

The Balkans. We have had inquiries in the past by the DCAA and the civil fraud division of the United States Department of Justice into possible overcharges for work performed during 1996 through 2000 under a contract in the Balkans, which inquiry has not yet been completed by the Department of Justice. Based on an internal investigation, we credited our customer approximately $2 million during 2000 and 2001 related to our work in the Balkans as a result of billings for which support was not readily available. We believe that the preliminary Department of Justice inquiry relates to potential overcharges in connection with a part of the Balkans contract under which approximately $100 million in work was done. We beli eve that any allegations of overcharges would be without merit.

Nigerian joint venture and investigations

Foreign Corrupt Practices Act investigation. The SEC is conducting a formal investigation into payments made in connection with the construction and subsequent expansion by TSKJ of a multibillion dollar natural gas liquefaction complex and related facilities at Bonny Island in Rivers State, Nigeria. The United States Department of Justice is also conducting an investigation. TSKJ is a private limited liability company registered in Madeira, Portugal whose members are Technip SA of France, Snamprogetti Netherlands B.V., which is an affiliate of ENI SpA of Italy, JGC Corporation of Japan, and Kellogg Brown & Root, each of which owns 25% of the venture.

The SEC and the Department of Justice have been reviewing these matters in light of the requirements of the United States Foreign Corrupt Practices Act. We have produced documents to the SEC both voluntarily and pursuant to subpoenas, and intend to make our employees available to the SEC for testimony. In addition, we understand that the SEC has issued a subpoena to A. Jack Stanley, who most recently served as a consultant and chairman of Kellogg Brown & Root, and to other current and former Kellogg Brown & Root employees. We further understand that the Department of Justice has invoked its authority under a sitting grand jury to obtain letters rogatory for the purpose of obtaining information abroad.


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and Financial Crimes Commission. We also notified the other owners of TSKJ of the recently uncovered information and asked each of them to conduct their own investigation.

If violations of the FCPA were found, we could be subject to civil penalties of $500,000 per violation and criminal penalties could range up to the greater of $2 million per violation or twice the gross pecuniary gain or loss.

Bidding practices investigation. In connection with the investigation into payments made in connection with the Nigerian project, information has been uncovered suggesting that Mr. Stanley and other former employees may have engaged in coordinated bidding with one or more competitors on certain foreign construction projects and that such coordination possibly began as early as the mid-1980s, which was significantly before our 1998 acquisition of Dresser Industries.

There can be no assurance that the results of these investigations will not have a material adverse effect on our business and results of operations.

Operations in Iran

We received and responded to an inquiry in mid-2001 from the Office of Foreign Assets Control (OFAC) of the United States Treasury Department with respect to operations in Iran by a Halliburton subsidiary that is incorporated in the Cayman Islands. The OFAC inquiry requested information with respect to compliance with the Iranian Transaction


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Regulations. These regulations prohibit United States citizens, including United States corporations and other United States business organizations, from engaging in commercial, financial, or trade transactions with Iran, unless authorized by OFAC or exempted by statute. Our 2001 written response to OFAC stated that we believed that we were in compliance with applicable sanction regulations. In January 2004, we received a follow-up letter from OFAC requesting additional information. We responded to this request on March 19, 2004. We understand this matter has now been referred by OFAC to the Department of Justice. In July 2004, we received a grand jury subpoena from an Assistant United States District Attorney requesting the production of documents. We are cooperating with the government’s investigation and ha ve responded to the subpoena by producing documents on September 16, 2004.

Separate from the OFAC inquiry, we completed a study in 2003 of our activities in Iran during 2002 and 2003 and concluded that these activities were in compliance with applicable sanction regulations. These sanction regulations require isolation of entities that conduct activities in Iran from contact with United States citizens or managers of United States companies. Notwithstanding our conclusions that our activities in Iran were not in violation of United States laws and regulations, we have recently announced that, after fulfilling our current contractual obligations within Iran, we intend to cease operations within that country and to withdraw from further activities there.

Liquidity

Working capital requirements related to Iraq work

As described in “Legal Matters - United States Government contract work” above, it is possible that we may, or may be required to, withhold additional invoicing or make refunds to our customer related to the DCAA’s review of additional aspects of our services, some of which could be substantial, until these matters are resolved. Although we do not expect this to occur, such an outcome could materially and adversely affect our liquidity.

Credit facilities

We currently have:

a $700 million revolving credit facility, which expires in October 2006; and

a $500 million 364-day revolving credit facility, which expires in July 2005.

We experience increased working capital requirements from time to time associated with our business. An increased demand for working capital could affect our liquidity needs.

Geopolitical and International Environment

International and Political Events

A significant portion of our revenue is derived from our non-United States operations, which exposes us to risks inherent in doing business in each of the more than 100 other countries in which we transact business. The occurrence of any of the risks described below could have a material adverse effect on our consolidated results of operations and consolidated financial condition.

Our operations in more than 100 countries other than the United States accounted for approximately 78% of our consolidated revenue during 2004, 73% of our consolidated revenue during 2003, and 67% of our consolidated revenue during 2002. Based on the location of services provided and products sold, 26% of our consolidated revenue in 2004 and 15% in 2003 was from Iraq, primarily related to our work for the United States Government. Revenue from Iraq represented less than 10% in 2002. Operations in countries other than the United States are subject to various risks peculiar to each country. With respect to any particular country, these risks may include:

expropriation and nationalization of our assets in that country;

political and economic instability;

civil unrest, acts of terrorism, force majeure, war, or other armed conflict;

natural disasters, including those related to earthquakes and flooding;


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inflation;

currency fluctuations, devaluations, and conversion restrictions;

confiscatory taxation or other adverse tax policies;

governmental activities that limit or disrupt markets, restrict payments, or limit the movement of funds;

governmental activities that may result in the deprivation of contract rights; and

trade restrictions and economic embargoes imposed by the United States and other countries, including current limitations on our ability to provide products and services to Iran and Syria, which are significant producers of oil and gas.

Due to the unsettled political conditions in many oil-producing countries and countries in which we provide governmental logistical support, our revenue and profits are subject to the adverse consequences of war, the effects of terrorism, civil unrest, strikes, currency controls, and governmental actions. Countries where we operate that have significant amounts of political risk include: Afghanistan, Algeria, Indonesia, Iran, Iraq, Nigeria, Russia, and Venezuela. In addition, military action or continued unrest in the Middle East could impact the supply and pricing for oil and gas, disrupt our operations in the region and elsewhere, and increase our costs for security worldwide.

In addition, investigations by governmental authorities (see “Legal Matters - Nigerian joint venture and investigations” above), as well as the social, economic, and political climate in Nigeria, could materially and adversely affect our Nigerian business and operations. In September 2004, the Federal Republic of Nigeria issued a directive banning Halliburton Energy Services Nigeria Limited, one of our subsidiaries, from receiving contracts from the Nigerian government or from companies controlled by the Nigerian government. We believe this directive to have been issued as a result of an adverse reaction in Nigeria to the theft of radioactive material that we used in wireline logging operations, which was subsequently recovered and returned to Nigeria. We are currently working with the Nigerian governmen t to obtain a lifting of the ban. If the ban is not lifted, it could have an adverse effect on our ability to conduct business in Nigeria. Our facilities and our employees are under threat of attack in some countries where we operate, including Iraq and Saudi Arabia. In addition, the risk of loss of life of our personnel and of our subcontractors in these areas continues.

Military Action, Other Armed Conflicts, or Terrorist Attacks

Military action in Iraq, increasing military tension involving North Korea, as well as the terrorist attacks of September 11, 2001 and subsequent terrorist attacks, threats of attacks, and unrest, have caused instability in the world’s financial and commercial markets and have significantly increased political and economic instability in some of the geographic areas in which we operate. Acts of terrorism and threats of armed conflicts in or around various areas in which we operate, such as the Middle East and Indonesia, could limit or disrupt markets and our operations, including disruptions resulting from the evacuation of personnel, cancellation of contracts, or the loss of personnel or assets.

Such events may cause further disruption to financial and commercial markets and may generate greater political and economic instability in some of the geographic areas in which we operate. In addition, any possible reprisals as a consequence of the war and ongoing military action in Iraq, such as acts of terrorism in the United States or elsewhere, could materially and adversely affect us in ways we cannot predict at this time.

Income Taxes

We have operations in more than 100 countries other than the United States. Consequently, we are subject to the jurisdiction of a significant number of taxing authorities. The income earned in these various jurisdictions is taxed on differing bases, including net income actually earned, net income deemed earned and revenue based tax withholding. The final determination of our tax liabilities involves the interpretation of local tax laws, tax treaties and related authorities in each jurisdiction as well as the significant use of estimates and assumptions regarding the scope of future operations and results


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achieved and the timing and nature of income earned and expenditures incurred. Changes in the operating environment including changes in tax law and currency/repatriation controls could impact the determination of our tax liabilities for a tax year.

Foreign Exchange and Currency Risks

A sizable portion of our consolidated revenue and consolidated operating expenses are in foreign currencies. As a result, we are subject to significant risks, including:

foreign exchange risks resulting from changes in foreign exchange rates and the implementation of exchange controls; and

limitations on our ability to reinvest earnings from operations in one country to fund the capital needs of our operations in other countries.

We conduct business in countries that have nontraded or “soft” currencies which, because of their restricted or limited trading markets, may be more difficult to exchange for “hard” currency. We may accumulate cash in soft currencies and we may be limited in our ability to convert our profits into United States dollars or to repatriate the profits from those countries.

We selectively use hedging transactions to limit our exposure to risks from doing business in foreign currencies. For those currencies that are not readily convertible, our ability to hedge our exposure is limited because financial hedge instruments for those currencies are nonexistent or limited. Our ability to hedge is also limited because pricing of hedging instruments, where they exist, is often volatile and not necessarily efficient.

In addition, the value of the derivative instruments could be impacted by:

adverse movements in foreign exchange rates;

interest rates;

commodity prices; or

the value and time period of the derivative being different than the exposures or cash flows being hedged.

Customers and Business

Exploration and Production Activity

Demand for our services and products depends on oil and natural gas industry activity and expenditure levels that are directly affected by trends in oil and natural gas prices.

Demand for our products and services is particularly sensitive to the level of exploration, development, and production activity of, and the corresponding capital spending by, oil and natural gas companies, including national oil companies. Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of other factors that are beyond our control. Any prolonged reduction in oil and natural gas prices will depress the immediate levels of exploration, development, and production activity, often reflected as changes in rig counts. Perceptions of longer-term lower oil and natural gas prices by oil and gas companies can similarly reduce or defer major expenditures given the long-term nature o f many large-scale development projects. Lower levels of activity result in a corresponding decline in the demand for our oil and natural gas well services and products that could have a material adverse effect on our revenue and profitability. Factors affecting the prices of oil and natural gas include:

governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves;

global weather conditions and natural disasters;

worldwide political, military, and economic conditions;

the level of oil production by non-OPEC countries and the available excess production capacity within OPEC;

economic growth in China and India;


	57

oil refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas;

the cost of producing and delivering oil and gas;

potential acceleration of development of alternative fuels; and

the level of demand for oil and natural gas, especially demand for natural gas in the United States.

Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. Spending on exploration and production activities and capital expenditures for refining and distribution facilities by large oil and gas companies have a significant impact on the activity levels of our businesses.

Barracuda-Caratinga Project

See Note 3 to the consolidated financial statements for a discussion of this project and “Fixed-Price Engineering and Construction Projects” below.

Governmental and Capital Spending

Our business is directly affected by changes in governmental spending and capital expenditures by our customers. Some of the changes that may materially and adversely affect us include:

a decrease in the magnitude of governmental spending and outsourcing for military and logistical support of the type that we provide. For example, the current level of government services being provided in the Middle East may not continue for an extended period of time;

an increase in the magnitude of governmental spending and outsourcing for military and logistical support, which can materially and adversely affect our liquidity needs as a result of additional or continued working capital requirements to support this work;

a decrease in capital spending by governments for infrastructure projects of the type that we undertake;

the consolidation of our customers, which has:

caused customers to reduce their capital spending, which has in turn reduced the demand for our services and products; and

resulted in customer personnel changes, which in turn affects the timing of contract negotiations and settlements of claims and claim negotiations with engineering and construction customers on cost variances and change orders on major projects;

adverse developments in the business and operations of our customers in the oil and gas industry, including write-downs of reserves and reductions in capital spending for exploration, development, production, processing, refining, and pipeline delivery networks; and

ability of our customers to timely pay the amounts due us.

Customers

Both our Energy Services Group and KBR depend on a limited number of significant customers. While, except for the United States Government, none of these customers represented more than 10% of consolidated revenue in any period presented, the loss of one or more significant customers could have a material adverse effect on our business and our consolidated results of operations.

Acquisitions, Dispositions, Investments, and Joint Ventures

We may actively seek opportunities to maximize efficiency and value through various transactions, including purchases or sales of assets, businesses, investments or contractual arrangements or joint ventures. These transactions would be intended to result in the realization of savings, the creation of efficiencies, the generation of cash or income, or the reduction of risk. Acquisition transactions may be financed by additional borrowings or by the issuance of our common stock. These transactions may also affect our consolidated results of operations.


	58

These transactions also involve risks and we cannot ensure that:

any acquisitions would result in an increase in income;

any acquisitions would be successfully integrated into our operations;

any disposition would not result in decreased earnings, revenue, or cash flow;

any dispositions, investments, acquisitions, or integrations would not divert management resources; or

any dispositions, investments, acquisitions, or integrations would not have a material adverse effect on our results of operations or financial condition.

Now that we have resolved our asbestos and silica liability and our affected subsidiaries have exited Chapter 11 reorganization proceedings, we intend to separate KBR from Halliburton, which could include a transaction involving a spin-off, split-off, public offering, or sale of KBR or its operations. In order to maximize KBR’s value for our shareholders, and to determine the most appropriate form of the transaction and its components, it may be necessary for KBR to establish a track record of positive earnings for a number of quarters and to seek resolution of governmental issues, investigations, and other disputes.

We conduct some operations through joint ventures, where control may be shared with unaffiliated third parties. As with any joint venture arrangement, differences in views among the joint venture participants may result in delayed decisions or in failures to agree on major issues. We also cannot control the actions of our joint venture partners, including any nonperformance, default, or bankruptcy of our joint venture partners. These factors could potentially materially and adversely affect the business and operations of the joint venture and, in turn, our business and operations.

Fixed-Price Contracts

We contract to provide services either on a cost-reimbursable basis or on a fixed-price basis, with fixed-price (or lump-sum) contracts accounting for approximately 11% of consolidated revenue for the year ended December 31, 2004 and 14% for the year ended December 31, 2003. We bear the risk of cost overruns, operating cost inflation, labor availability and productivity, and supplier and subcontractor pricing and performance in connection with projects covered by fixed-price contracts. Our failure to estimate accurately the resources and time required for a fixed-price project, or our failure to complete our contractual obligations within the time frame and costs committed, could have a material adverse effect on our business, results of operations, and financial condition.

Environmental Requirements

Our businesses are subject to a variety of environmental laws, rules, and regulations in the United States and other countries, including those covering hazardous materials and requiring emission performance standards for facilities. For example, our well service operations routinely involve the handling of significant amounts of waste materials, some of which are classified as hazardous substances. We also store, transport, and use radioactive and explosive materials in certain of our operations. Environmental requirements include, for example, those concerning:

the containment and disposal of hazardous substances, oilfield waste, and other waste materials;

the importation and use of radioactive materials;

the use of underground storage tanks; and

the use of underground injection wells.

Environmental and other similar requirements generally are becoming increasingly strict. Sanctions for failure to comply with these requirements, many of which may be applied retroactively, may include:

administrative, civil, and criminal penalties;

revocation of permits to conduct business; and

corrective action orders, including orders to investigate and/or clean up contamination.


	59

Failure on our part to comply with applicable environmental requirements could have a material adverse effect on our consolidated financial condition. We are also exposed to costs arising from environmental compliance, including compliance with changes in or expansion of environmental requirements, such as the potential regulation in the United States of our Energy Services Group’s hydraulic fracturing services and products as underground injection, which could have a material adverse effect on our business, financial condition, operating results, or cash flows.

We are exposed to claims under environmental requirements and, from time to time such claims have been made against us. In the United States, environmental requirements and regulations typically impose strict liability. Strict liability means that in some situations we could be exposed to liability for cleanup costs, natural resource damages, and other damages as a result of our conduct that was lawful at the time it occurred or the conduct of prior operators or other third parties. Liability for damages arising as a result of environmental laws could be substantial and could have a material adverse effect on our consolidated results of operations.

Changes in environmental requirements may negatively impact demand for our services. For example, oil and natural gas exploration and production may decline as a result of environmental requirements (including land use policies responsive to environmental concerns). Such a decline, in turn, could have a material adverse effect on us.

Intellectual Property Rights

We rely on a variety of intellectual property rights that we use in our products and services. We may not be able to successfully preserve these intellectual property rights in the future and these rights could be invalidated, circumvented, or challenged. In addition, the laws of some foreign countries in which our products and services may be sold do not protect intellectual property rights to the same extent as the laws of the United States. Our failure to protect our proprietary information and any successful intellectual property challenges or infringement proceedings against us could materially and adversely affect our competitive position.

Technology

The market for our products and services is characterized by continual technological developments to provide better and more reliable performance and services. If we are not able to design, develop, and produce commercially competitive products and to implement commercially competitive services in a timely manner in response to changes in technology, our business and revenue could be materially and adversely affected and the value of our intellectual property may be reduced. Likewise, if our proprietary technologies, equipment and facilities, or work processes become obsolete, we may no longer be competitive and our business and revenue could be materially and adversely affected.

Systems

Our business could be materially and adversely affected by problems encountered in the installation of a new SAP financial system to replace the current systems for KBR.

Technical Personnel

Many of the services that we provide and the products that we sell are complex and highly engineered and often must perform or be performed in harsh conditions. We believe that our success depends upon our ability to employ and retain technical personnel with the ability to design, utilize, and enhance these products and services. In addition, our ability to expand our operations depends in part on our ability to increase our skilled labor force. The demand for skilled workers is high and the supply is limited. A significant increase in the wages paid by competing employers could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. If either of these events were to occur, our cost structure could increase, our margins could decrease, and our growth potential coul d be impaired.


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Weather

Our businesses could be materially and adversely affected by severe weather, particularly in the Gulf of Mexico where we have significant operations. Repercussions of severe weather conditions may include:

evacuation of personnel and curtailment of services;

weather-related damage to offshore drilling rigs resulting in suspension of operations;

weather-related damage to our facilities;

inability to deliver materials to jobsites in accordance with contract schedules; and

loss of productivity.

Because demand for natural gas in the United States drives a disproportionate amount of our Energy Services Group’s United States business, warmer than normal winters in the United States are detrimental to the demand for our services to gas producers.


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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Halliburton Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Exchange Act Rule 13a-15(f).

Internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Further, because of changes in conditions, the effectiveness of internal control over financial reporting may vary over time.

Under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, we conducted an evaluation to assess the effectiveness of our internal control over financial reporting as of December 31, 2004 based upon criteria set forth in the framework Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that, as of December 31, 2004, our internal control over financial reporting is effective.

Our assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by our independent registered public accounting firm, KPMG LLP. Their audit opinion on our assessment of internal control over financial reporting is on page 64.

HALLIBURTON COMPANY

/s/ David J. Lesar	/s/ C. Christopher Gaut
David J. Lesar	C. Christopher Gaut
Chairman of the Board,	Executive Vice President and
President, and	Chief Financial Officer
Chief Executive Officer


	62

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders

Halliburton Company:

We have audited the accompanying consolidated balance sheets of Halliburton Company and subsidiaries as of December 31, 2004 and December 31, 2003, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2004. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Halliburton Company and subsidiaries as of December 31, 2004 and December 31, 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U. S. generally accepted accounting principles.

As described in Note 5 to the consolidated financial statements, the Company changed the composition of its reportable segments in 2004 and 2003. The amounts in the 2003 and 2002 consolidated financial statements related to reportable segments have been restated to conform to the 2004 composition of reportable segments.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Halliburton Company’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 25, 2005 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

February 25, 2005


	63

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders

Halliburton Company:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting appearing on page 62, that Halliburton Company maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Halliburton Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financia l reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance wit h authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Halliburton Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control - Integrated Framework issued by COSO. Also, in our opinion, Halliburton Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Halliburton Company and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2004, and our report dated February 25, 2005 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas

February 25, 2005


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HALLIBURTON COMPANY

Consolidated Statements of Operations

(Millions of dollars and shares except per share data)

	Years ended December 31
	2004			2003			2002
Revenue:
Services	$	18,327		$	14,383		$	10,658
Product sales		2,137			1,863			1,840
Equity in earnings of unconsolidated affiliates, net		2			25			74
Total revenue		20,466			16,271			12,572
Operating costs and expenses:
Cost of services		17,441			13,589			10,737
Cost of sales		1,882			1,679			1,642
General and administrative		361			330			335
Gain on sale of business assets, net		(55	)		(47	)		(30	)
Total operating costs and expenses		19,629			15,551			12,684
Operating income (loss)		837			720			(112	)
Interest expense		(229	)		(139	)		(113	)
Interest income		44			30			32
Foreign currency gains (losses), net		(3	)		-			(25	)
Other, net		2			1			(10	)
Income (loss) from continuing operations before
income taxes, minority interest, and change
in accounting principle		651			612			(228	)
Provision for income taxes		(241	)		(234	)		(80	)
Minority interest in net income of subsidiaries		(25	)		(39	)		(38	)
Income (loss) from continuing operations before
change in accounting principle		385			339			(346	)
Loss from discontinued operations, net of tax (provision)
benefit of $180, $(6), and $154		(1,364	)		(1,151	)		(652	)
Cumulative effect of change in accounting principle, net
of tax benefit of $5		-			(8	)		-
Net loss	$	(979	)	$	(820	)	$	(998	)

Basic income (loss) per share:
Income (loss) from continuing operations before change in
accounting principle	$	0.88		$	0.78		$	(0.80	)
Loss from discontinued operations, net		(3.13	)		(2.65	)		(1.51	)
Cumulative effect of change in accounting principle, net		-			(0.02	)		-
Net loss	$	(2.25	)	$	(1.89	)	$	(2.31	)

Diluted income (loss) per share:
Income (loss) from continuing operations before change in
accounting principle	$	0.87		$	0.78		$	(0.80	)
Loss from discontinued operations, net		(3.09	)		(2.64	)		(1.51	)
Cumulative effect of change in accounting principle, net		-			(0.02	)		-
Net loss	$	(2.22	)	$	(1.88	)	$	(2.31	)

Basic weighted average common shares outstanding		437			434			432
Diluted weighted average common shares outstanding		441			437			432

See notes to consolidated financial statements.


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HALLIBURTON COMPANY

Consolidated Balance Sheets

(Millions of dollars and shares except per share data)

	December 31
	2004			2003
Assets
Current assets:
Cash and equivalents	$	2,808		$	1,815
Receivables:
Notes and accounts receivable (less allowance for bad debts of $127 and $175)		2,873			2,909
Unbilled work on uncompleted contracts		1,812			1,760
Insurance for asbestos- and silica-related liabilities		1,066			96
Total receivables		5,751			4,765
Inventories		723			695
Other current assets		680			644
Total current assets		9,962			7,919
Net property, plant, and equipment		2,553			2,526
Goodwill		795			670
Noncurrent deferred income taxes		780			774
Equity in and advances to related companies		541			579
Insurance for asbestos- and silica-related liabilities		350			2,038
Other assets		815			993
Total assets	$	15,796		$	15,499
Liabilities and Shareholders’ Equity
Current liabilities:
Asbestos- and silica-related liabilities	$	2,408		$	2,507
Accounts payable		2,271			1,776
Advanced billings on uncompleted contracts		553			741
Accrued employee compensation and benefits		473			400
Current maturities of long-term debt		347			22
Other current liabilities		1,012			1,118
Total current liabilities		7,064			6,564
Long-term debt		3,593			3,415
Employee compensation and benefits		635			801
Asbestos- and silica-related liabilities		37			1,579
Other liabilities		427			493
Total liabilities		11,756			12,852
Minority interest in consolidated subsidiaries		108			100
Shareholders’ equity:
Common shares, par value $2.50 per share - authorized 1,000 and 600 shares,
issued 458 and 457 shares		1,146			1,142
Paid-in capital in excess of par value		277			273
Common shares to be contributed to asbestos trust - 59.5 shares		2,335			-
Deferred compensation		(74	)		(64	)
Accumulated other comprehensive income		(146	)		(298	)
Retained earnings		871			2,071
		4,409			3,124
Less 16 and 18 shares of treasury stock, at cost		477			577
Total shareholders’ equity		3,932			2,547
Total liabilities and shareholders’ equity	$	15,796		$	15,499

See notes to consolidated financial statements.


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HALLIBURTON COMPANY

Consolidated Statements of Shareholders’ Equity

(Millions of dollars and shares)

	2004			2003			2002
Balance at January 1	$	2,547		$	3,558		$	4,752
Dividends and other transactions with shareholders		(123	)		(174	)		(151	)
Common shares to be contributed to asbestos
trust - 59.5 shares		2,335			-			-
Comprehensive loss:
Net loss		(979	)		(820	)		(998	)

Cumulative translation adjustment		33			43			69
Realization of (gains) losses included in net loss		(1	)		15			15
Net cumulative translation adjustment		32			58			84

Pension liability adjustments		115			(88	)		(130	)
Unrealized gains on investments and derivatives		5			13			1
Total comprehensive loss		(827	)		(837	)		(1,043	)
Balance at December 31	$	3,932		$	2,547		$	3,558

See notes to consolidated financial statements.


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HALLIBURTON COMPANY

Consolidated Statements of Cash Flows

(Millions of dollars)

	Years ended December 31
	2004			2003			2002
Cash flows from operating activities:
Net loss	$	(979	)	$	(820	)	$	(998	)
Adjustments to reconcile net income (loss) to net cash from operations:
Loss from discontinued operations		1,364			1,151			652
Asbestos and silica charges not included in discontinued operations, net		-			-			530
Depreciation, depletion, and amortization		509			518			505
Provision (benefit) for deferred income taxes, including $(167), $27, and
$(133) related to discontinued operations		(176	)		(86	)		(151	)
Distributions from (advances to) related companies, net of equity
in (earnings) losses		(39	)		13			3
Change in accounting principle, net		-			8			-
Gain on sale of assets		(62	)		(52	)		(25	)
Asbestos and silica liability payment related to Chapter 11 filing		(119	)		(311	)		-
Other changes:
Accounts receivable		(506	)		(1,442	)		675
Accounts receivable facilities transactions		519			(180	)		180
Inventories		(22	)		7			62
Accounts payable		428			676			71
Other		11			(257	)		58
Total cash flows from operating activities		928			(775	)		1,562
Cash flows from investing activities:
Capital expenditures		(575	)		(515	)		(764	)
Sales of property, plant, and equipment		166			107			266
Dispositions (acquisitions) of businesses assets,
net of cash disposed		102			224			170
Proceeds from sale of securities		22			57			62
Investments - restricted cash		89			(18	)		(187	)
Other investing activities		(30	)		(51	)		(20	)
Total cash flows from investing activities		(226	)		(196	)		(473	)
Cash flows from financing activities:
Proceeds from long-term borrowings, net of offering costs		496			2,192			66
Proceeds from exercises of stock options		63			21			-
Payments to reacquire common stock		(7	)		(6	)		(4	)
Borrowings (repayments) of short-term debt, net		(7	)		(32	)		(2	)
Payments on long-term borrowings		(20	)		(296	)		(81	)
Payments of dividends to shareholders		(221	)		(219	)		(219	)
Other financing activities		(21	)		(24	)		(8	)
Total cash flows from financing activities		283			1,636			(248	)
Effect of exchange rate changes on cash		8			43			(24	)
Increase in cash and equivalents		993			708			817
Cash and equivalents at beginning of year		1,815			1,107			290
Cash and equivalents at end of year	$	2,808		$	1,815		$	1,107
Supplemental disclosure of cash flow information:
Cash payments during the year for:
Interest	$	189		$	114		$	104
Income taxes	$	265		$	173		$	94

See notes to consolidated financial statements.


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HALLIBURTON COMPANY

Notes to Consolidated Financial Statements

Note 1. Description of Company and Significant Accounting Policies

Description of Company. Halliburton Company’s predecessor was established in 1919 and incorporated under the laws of the State of Delaware in 1924. We are one of the world’s largest oilfield services companies and a leading provider of engineering and construction services. We have six business segments that are organized around how we manage our business: Production Optimization, Fluid Systems, Drilling and Formation Evaluation, and Digital and Consulting Solutions (formerly Landmark and Other Energy Services), collectively, the Energy Services Group; and Government and Infrastructure and Energy and Chemicals, collectively known as KBR. Through our Energy Services Group, we provide a comp rehensive range of discrete and integrated products and services for the exploration, development, and production of oil and gas. We serve major national and independent oil and gas companies throughout the world. KBR provides a wide range of services to energy and industrial customers and governmental entities worldwide.

Use of estimates. Our financial statements are prepared in conformity with accounting principles generally accepted in the United States, requiring us to make estimates and assumptions that affect:

the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements; and

the reported amounts of revenue and expenses during the reporting period.

Ultimate results could differ from those estimates.

Basis of presentation. The consolidated financial statements include the accounts of our company and all of our subsidiaries which we control or variable interest entities for which we have determined that we are the primary beneficiary (see Note 20). All material intercompany accounts and transactions are eliminated. Investments in companies in which we have a significant influence are accounted for using the equity method, and if we do not have significant influence we use the cost method.

Certain prior year amounts have been reclassified to conform to the current year presentation.

Revenue recognition. We generally recognize revenue as services are rendered or products are shipped. Usually the date of shipment corresponds to the date upon which the customer takes title to the product and assumes all risks and rewards of ownership. The distinction between services and product sales is based upon the overall activity of the particular business operation. Training and consulting service revenue is recognized as the services are performed. In accordance with Emerging Issues Task Force Issue No. 00-21 (EITF No. 00-21), “Revenue Arrangements with Multiple Deliverables,” for contracts containing multiple deliverables entered into after June 30, 2003 that contain performance awards, award fees related to service components of the contract are recognized when they are awarded by our customer. For such contracts entered into prior to June 30, 2003, these award fees are recognized as services are performed based on our estimate of the amount to be awarded. For service-only contracts, award fees are recognized only when awarded by the customer. Revenue recognition for specialized products and services follows.

Revenue from contracts to provide construction, engineering, design, or similar services, almost all of which relates to KBR, is reported on the percentage-of-completion method of accounting. Progress is generally based upon physical progress, man-hours, or costs incurred, depending on the type of job. All known or anticipated losses on contracts are provided for when they become evident. Claims and change orders that are in the process of being negotiated with customers for extra work or changes in the scope of work are included in revenue when collection is deemed probable.

Accounting for government contracts. Most of the services provided to the United States government are governed by cost-reimbursable contracts. Generally, these contracts contain both a base fee (a fixed profit percentage applied to our actual costs to complete the work) and an award fee (a variable profit percentage, subject to our


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customer’s discretion and tied to the specific performance measures defined in the contract). Similar to many cost-reimbursable contracts, these government contracts are typically subject to audit and adjustment by our customer. Services under our LogCAP, RIO, PCO Oil South, and Balkans support contracts are examples of these types of arrangements.

For these contracts, base fee revenue is recorded at the time services are performed based upon actual project costs incurred and include a reimbursement fee for general, administrative, and overhead costs and the base fee. The general, administrative, and overhead fees are estimated periodically in accordance with government contract accounting regulations and may change based on actual costs incurred or based upon the volume of work performed. Revenue may be adjusted for our estimate of costs that may be categorized as disputed or unallowable as a result of cost overruns or the audit process.

Award fees are generally evaluated and granted periodically by our customer. For contracts entered into prior to June 30, 2003, all award fees are recognized during the term of the contract based on our estimate of amounts to be awarded. Once award fees are granted and task orders underlying the work are definitized, we adjust our estimate of award fees to actual amounts earned. Our estimates are often based on our past award experience for similar types of work. In accordance with EITF No. 00-21, for contracts containing multiple deliverables entered into subsequent to June 30, 2003 (such as PCO Oil South), we do not recognize award fees for the services portion of the contract based on estimates. Instead, they are recognized only when definitized and awarded by the customer. Also, for service-only contracts, awa rd fees are recognized only when awarded by the customer. Award fees on government construction contracts are recognized during the term of the contract based on our estimate of the amount of fees to be awarded.

Software sales. Software sales of perpetual software licenses, net of deferred maintenance fees, are recorded as revenue upon shipment. Sales of use licenses are recognized as revenue over the license period. Post-contract customer support agreements are recorded as deferred revenue and recognized as revenue ratably over the contract period, generally a one-year duration.

Research and development. Research and development expenses are charged to income as incurred. Research and development expenses were $234 million in 2004, $221 million in 2003, and $233 million in 2002, of which over 96% was company-sponsored in each year.

Software development costs. Costs of developing software for sale are charged to expense when incurred, as research and development, until technological feasibility has been established for the product. Once technological feasibility is established, software development costs are capitalized until the software is ready for general release to customers. We capitalized costs related to software developed for resale of $16 million in 2004, $17 million in 2003 and $11 million in 2002. Amortization expense of software development costs was $22 million for 2004, $17 million for 2003 and $19 million for 2002. Once the software is ready for release, amortization of the software development costs begins. Cap italized software development costs are amortized over periods which do not exceed five years.

Cash equivalents. We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Inventories. Inventories are stated at the lower of cost or market. Cost represents invoice or production cost for new items and original cost less allowance for condition for used material returned to stock. Production cost includes material, labor, and manufacturing overhead. Some domestic manufacturing and field service finished products and parts inventories for drill bits, completion products, and bulk materials are recorded using the last-in, first-out method. The cost of over 95% of the remaining inventory is recorded on the average cost method, with the remainder on the first-in, first-out method.

Allowance for bad debts. We establish an allowance for bad debts through a review of several factors including: historical collection experience; current aging status of the customer accounts; financial condition of our customers; and whether the receivables involve retentions or billing disputes.


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Property, plant, and equipment. Other than those assets that have been written down to their fair values due to impairment, property, plant, and equipment are reported at cost less accumulated depreciation, which is generally provided on the straight-line method over the estimated useful lives of the assets. Some assets are depreciated on accelerated methods. Accelerated depreciation methods are also used for tax purposes, wherever permitted. Upon sale or retirement of an asset, the related costs and accumulated depreciation are removed from the accounts and any gain or loss is recognized. We follow the successful efforts method of accounting for oil and gas properties.

Goodwill. The reported amounts of goodwill for each reporting unit are reviewed for impairment on an annual basis and more frequently when negative conditions such as significant current or projected operating losses exist. The annual impairment test for goodwill is a two-step process and involves comparing the estimated fair value of each reporting unit to the reporting unit’s carrying value, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered impaired, and the second step of the impairment test is unnecessary. If the carrying amount of a reporting unit exceeds its fair value, the second step of the goodwill im pairment test would be performed to measure the amount of impairment loss to be recorded, if any. Our annual impairment tests resulted in no goodwill impairment.

Evaluating impairment of long-lived assets. When events or changes in circumstances indicate that long-lived assets other than goodwill may be impaired, an evaluation is performed. For an asset classified as held for use, the estimated future undiscounted cash flows associated with the asset are compared to the asset’s carrying amount to determine if a write-down to fair value is required. When an asset is classified as held for sale, the asset’s book value is evaluated and adjusted to the lower of its carrying amount or fair value less cost to sell. In addition, depreciation (amortization) is ceased while it is classified as held for sale.

Income taxes. We recognize the amount of taxes payable or refundable for the year. In addition, deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in the financial statements or tax returns. A valuation allowance is provided for deferred tax assets if it is more likely than not that these items will not be realized.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that we will realize the benefits of these deductible differences, net of the existing valuat ion allowances.

We generally do not provide income taxes on the undistributed earnings of non-United States subsidiaries because such earnings are intended to be reinvested indefinitely to finance foreign activities. Taxes are provided as necessary with respect to earnings which are not permanently reinvested. The American Job Creations Act of 2004 introduced a special dividends received deduction with respect to the repatriation of certain foreign earnings to a United States taxpayer under certain circumstances. Based on our analysis of the Act, we do not expect to utilize the special deduction.

Derivative instruments. At times, we enter into derivative financial transactions to hedge existing or projected exposures to changing foreign currency exchange rates, interest rates, and commodity prices. We do not enter into derivative transactions for speculative or trading purposes. We recognize all derivatives on the balance sheet at fair value. Derivatives that are not hedges are adjusted to fair value and reflected through the results of operations. If the


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derivative is designated as a hedge, depending on the nature of the hedge, changes in the fair value of derivatives are either offset against:

the change in fair value of the hedged assets, liabilities, or firm commitments through earnings; or

recognized in other comprehensive income until the hedged item is recognized in earnings.

The ineffective portion of a derivative’s change in fair value is recognized in earnings. Recognized gains or losses on derivatives entered into to manage foreign exchange risk are included in foreign currency gains and losses in the consolidated statements of income. Gains or losses on interest rate derivatives are included in interest expense and gains or losses on commodity derivatives are included in operating income.

Foreign currency translation. Foreign entities whose functional currency is the United States dollar translate monetary assets and liabilities at year-end exchange rates, and non-monetary items are translated at historical rates. Income and expense accounts are translated at the average rates in effect during the year, except for depreciation, cost of product sales and revenue, and expenses associated with non-monetary balance sheet accounts, which are translated at historical rates. Gains or losses from changes in exchange rates are recognized in consolidated income in the year of occurrence. Foreign entities whose functional currency is not the United States dollar translate net assets at year-end rates and income and expense accounts at average exchange rates. Adjustments resulting from these translations are reflected in the consolidated statements of shareholders’ equity as cumulative translation adjustments.

Stock-based compensation. At December 31, 2004, we have six stock-based employee compensation plans. We account for these plans under the recognition and measurement principles of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. No cost for stock options granted is reflected in net income, as all options granted under our plans have an exercise price equal to the market value of the underlying common stock on the date of grant. In addition, no cost for the Employee Stock Purchase Plan is reflected in net income because it is not considered a compensatory plan.

The fair value of options at the date of grant was estimated using the Black-Scholes option pricing model. The weighted average assumptions and resulting fair values of options granted are as follows:

	Assumptions											Weighted
												Average
				Expected			Expected					Fair Value of
	Risk-Free			Dividend			Life (in		Expected			Options
	Interest Rate			Yield			years)		Volatility			Granted
2004		3.7	%		1.3	%		5		54	%	$	13.37
2003		3.2	%		1.9	%		5		59	%	$	12.37
2002		2.9	%		2.7	%		5		63	%	$	6.89

Included in the pro forma compensation table below is the fair value of the employee stock purchase plan shares. The fair value of these shares was estimated using the Black-Scholes model with the following assumptions for 2004: risk-free interest rate of 2.6%; expected dividend yield of 1.3%; expected life of six months; and expected volatility of 27%.

The following table illustrates the effect on net loss and loss per share if we had applied the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee compensation.


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	Years ended December 31
Millions of dollars except per share data	2004			2003			2002
Net loss, as reported	$	(979	)	$	(820	)	$	(998	)
Total stock-based employee compensation
expense determined under fair value
based method for all awards (except
restricted stock), net of related tax
effects		(28	)		(30	)		(26	)
Net loss, pro forma	$	(1,007	)	$	(850	)	$	(1,024	)

Basic loss per share:
As reported	$	(2.25	)	$	(1.89	)	$	(2.31	)
Pro forma	$	(2.31	)	$	(1.96	)	$	(2.37	)
Diluted loss per share:
As reported	$	(2.22	)	$	(1.88	)	$	(2.31	)
Pro forma	$	(2.28	)	$	(1.95	)	$	(2.37	)

We also maintain a restricted stock program wherein the fair market value of the stock on the date of issuance is amortized and ratably charged to income over the average period during which the restrictions lapse. The related expense, net of tax, reflected in net income as reported was $14 million in 2004, $13 million in 2003, and $24 million in 2002.

See Note 15 for further detail on stock incentive plans.

We estimate that the effect on net income and earnings per share in the periods following adoption of SFAS No. 123R will be consistent with our pro forma disclosure under SFAS No. 123, except that estimated forfeitures will be considered in the calculation of compensation expense under SFAS No. 123R. Additionally, the actual effect on net income and earnings per share will vary depending upon the number of options granted in 2005 compared to prior years, and the number of shares purchased under the Employee Stock Purchase Plan. Further, we have not yet determined the actual model we will use to calculate fair value.

Note 2. Percentage-of-Completion Contracts

Revenue from contracts to provide construction, engineering, design, or similar services is reported on the percentage-of-completion method of accounting using measurements of progress toward completion appropriate for the work performed. Commonly used measurements are physical progress, man-hours, and costs incurred.

Billing practices for these projects are governed by the contract terms of each project based upon costs incurred, achievement of milestones, or pre-agreed schedules. Billings do not necessarily correlate with revenue recognized under the percentage-of-completion method of accounting. Billings in excess of recognized revenue are recorded in “Advance


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billings on uncompleted contracts.” When billings are less than recognized revenue, the difference is recorded in “Unbilled work on uncompleted contracts.” With the exception of claims and change orders that are in the process of being negotiated with customers, unbilled work is usually billed during normal billing processes following achievement of the contractual requirements.

Recording of profits and losses on long-term contracts requires an estimate of the total profit or loss over the life of each contract. This estimate requires consideration of contract revenue, change orders and claims reduced by costs incurred, and estimated costs to complete. Anticipated losses on contracts are recorded in full in the period they become evident. Except in a limited number of projects that have significant uncertainties in the estimation of costs, we do not delay income recognition until projects have reached a specified percentage of completion. Generally, profits are recorded from the commencement date of the contract based upon the total estimated contract profit multiplied by the current percentage complete for the contract.

When recording the revenue and the associated unbilled receivable for unapproved claims, we only accrue an amount equal to the costs incurred related to probable unapproved claims. Therefore, the difference between the probable unapproved claims included in determining contract profit or loss and the probable unapproved claims recorded in unbilled work on uncompleted contracts relates to forecasted costs which have not yet been incurred. The amounts included in determining the profit or loss on contracts and the amounts booked to “Unbilled work on uncompleted contracts” for each period are as follows:

	Total Probable									Probable
	Unapproved Claims									Unapproved Claims
	(included in determining									Accrued Revenue
	contract profit or loss)									(unbilled work on uncompleted contracts)
Millions of dollars	2004			2003			2002			2004			2003			2002
Beginning balance	$	233		$	279		$	137		$	225		$	210		$	102
Additions		113			63			158			110			61			105
Claims resolved		(172	)		(94	)		(11	)		(165	)		(94	)		(11	)
Costs incurred during
period		-			-			-			6			63			19
Other		8			(15	)		(5	)		6			(15	)		(5	)
Ending balance	$	182		$	233		$	279		$	182		$	225		$	210

The probable unapproved claims as of December 31, 2004 relate to four contracts, most of which are complete or substantially complete. The additions in 2004 to probable unapproved claims include $110 million for contracts with Petroleos Mexicanos (PEMEX), which was reclassified from unapproved change orders.

A significant portion of the total probable unapproved claims ($153 million related to our consolidated entities and $45 million related to our unconsolidated related companies) arose from three completed projects with PEMEX that are currently subject to arbitration proceedings. In addition, we have “Other assets” of $64 million for previously approved services that are unpaid by PEMEX and have been included in these arbitration proceedings. Actual amounts we are


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seeking from PEMEX in the arbitration proceedings are in excess of these amounts. The arbitration proceedings are expected to extend through 2007.

The $172 million decrease for claims resolution primarily resulted from efforts to settle older contract issues and reflects the terms of the Barracuda-Caratinga agreement with Petroleo Brasilero SA (Petrobras). See Note 13. The agreement settled our probable unapproved claims of $114 million at December 31, 2003 for a payment in January 2005 of $79 million.

We have contracts with probable unapproved claims that will likely not be settled within one year totaling $153 million at December 31, 2004 and $204 million at December 31, 2003 included in the table above, which are reflected as “Other assets” on the consolidated balance sheets. Other probable unapproved claims that we believe will be settled within one year included in the table above have been recorded to “Unbilled work on uncompleted contracts” included in the “Total receivables” amount on the consolidated balance sheets.

Unapproved change orders. We have other contracts for which we are negotiating change orders to the contract scope and have agreed upon the scope of work but not the price. These change orders amount to $43 million at December 31, 2004. Unapproved change orders at December 31, 2003 were $97 million.

Unconsolidated related companies. Our unconsolidated related companies include probable unapproved claims as revenue to determine the amount of profit or loss for their contracts. Probable unapproved claims from our related companies are included in “Equity in and advances to related companies,” and our share totaled $51 million at December 31, 2004 and $10 million at December 31, 2003. In addition, our unconsolidated related companies are negotiating change orders to the contract scope where we have agreed upon the scope of work but not the price. Our share of these change orders totaled $37 million at December 31, 2004 and $59 million at December 31, 2003.

See Note 12 for discussion of government contract claims.

Note 3. Barracuda-Caratinga Project

In June 2000, Kellogg Brown & Root, Inc. (Kellogg Brown & Root) entered into a contract with Barracuda & Caratinga Leasing Company B.V., the project owner, to develop the Barracuda and Caratinga crude oilfields, which are located off the coast of Brazil. The construction manager and project owner’s representative is Petrobras, the Brazilian national oil company. When completed, the project will consist of two converted supertankers, Barracuda and Caratinga, which will be used as floating production, storage, and offloading units, commonly referred to as FPSOs. In addition, there will be 32 hydrocarbon production wells, 22 water injection wells, and all subsea flow lines, umbilicals, and risers necessary to connect the underwater wells to the FPSOs. The original completion date for the Barracuda ve ssel was December 2003, and the original completion date for the Caratinga vessel was April 2004. The project has been significantly behind the original schedule, due in part to change orders from the project owner, and is in a financial loss position.

In December 2004, the Barracuda vessel achieved first oil after being moved offshore for sea trials and final inspections in October 2004, and the Caratinga vessel was moved offshore for sea trials and final inspections. The Caratinga vessel achieved first oil in February 2005. Pursuant to the settlement agreement with Petrobras described below, the Barracuda vessel must be completed by March 31, 2006, and the Caratinga vessel must be completed by June 30, 2006. While we anticipate meeting these completion targets, there can be no assurance that further delays will not occur.

Also in December 2004, Kellogg Brown & Root and Petrobras, on behalf of the project owner, reached an agreement to settle various claims between the parties. The agreement provides for:

the release of all claims of all parties that arise prior to the effective date of a final definitive agreement;

a payment to us in 2005 of $79 million as a result of change orders for remaining claims;


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payment by Petrobras of applicable value added taxes on the project, except for $8 million which has been paid by us;

the performance by Petrobras of certain work under the original contract;

the repayment by Kellogg Brown & Root of $300 million of advance payments by the end of February 2005, with interest on $74 million. Of this amount, $79 million was paid in 2004; and

revised milestones and other dates, including settlement of liquidated damages and an extension of time to the FPSO final acceptance dates.

As of December 31, 2004:

the project was approximately 92% complete;

the losses recorded include an estimated $24 million in liquidated damages based on the final agreement with Petrobras; and

the probable unapproved claims were reduced from $114 million at December 31, 2003 to zero based upon the final agreement with Petrobras.

Millions of dollars
Amount funded through December 31, 2004	$	586
Amounts to be paid/(received) in 2005:
Remaining repayment of $300 million advance		221
Payment to us relating to change orders		(138	)
Remaining project costs, net of revenue
received		93
Total cash shortfalls	$	762

Note 4. Acquisitions and Dispositions

Subsea 7, Inc. In January 2005, we completed the sale of our 50% interest in Subsea 7, Inc. to our joint venture partner, Siem Offshore (formerly DSND Subsea ASA), for approximately $200 million in cash. As a result of the transaction, we recorded a gain of approximately $110 million during the first quarter of 2005. We accounted for our 50% ownership of Subsea 7, Inc. using the equity method in our Production Optimization segment.

Surface Well Testing. In August 2004, we sold our surface well testing and subsea test tree operations within our Production Optimization segment to Power Well Service Holdings, LLC, an affiliate of First Reserve Corporation, for approximately $129 million, of which we received $126 million in cash. During 2004, we recorded a $54 million gain on the sale. For a limited period of time, we continue to have significant involvement with portions of these operations in certain countries and, therefore, have not recognized the gain from the sale of these operations as of December 31, 2004.

Enventure and WellDynamics. In the first quarter of 2004, Halliburton and Shell Technology Ventures (Shell, an unrelated party) agreed to restructure two joint venture companies, Enventure Global Technology LLC (Enventure) and WellDynamics B.V. (WellDynamics), in an effort to more closely align the ventures with near-term priorities in the core businesses of the venture owners. Prior to this transaction, Enventure (part of our Fluid Systems segment) and WellDynamics (formerly part of our Digital and Consulting Solutions segment) were owned equally by Shell and us. Shell acquired an additional 33.5% of Enventure, leaving us with 16.5% ownership in return for enhanced and extended


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agreements and licenses with Shell for its Poroflex™ expandable sand screens and a distribution agreement for its Versaflex™ expandable liner hangers. As a result of this transaction, we changed the way we account for our ownership in Enventure from the equity method to the cost method of accounting for investments. We acquired an additional 1% of WellDynamics from Shell, giving us 51% ownership and control of day-to-day operations. In addition, Shell received an option to obtain our remaining interest in Enventure for an additional 14% interest in WellDynamics. No gain or loss resulted from the transaction. Beginning in the first quarter of 2004, WellDynamics was consolidated and is now included in our Production Optimization segment. The consolidation of WellDynamics resulted in an increase to our goodw ill of $109 million, which was previously carried as equity method goodwill in “Equity in and advances to related companies.”

Halliburton Measurement Systems. In May 2003, we sold certain assets of Halliburton Measurement Systems, which provides flow measurement and sampling systems, to NuFlo Technologies, Inc. for approximately $33 million in cash, subject to post-closing adjustments. The gain on the sale of Halliburton Measurement Systems’ assets was $24 million and was included in our Production Optimization segment.

Wellstream. In March 2003, we sold the assets relating to our Wellstream business, a global provider of flexible pipe products, systems, and solutions, to Candover Partners Ltd. for $136 million in cash. The assets sold included manufacturing plants in Newcastle upon Tyne, United Kingdom, and Panama City, Florida, as well as assets and contracts in Brazil. Wellstream had $34 million in goodwill recorded at the disposition date. The transaction resulted in a loss of $15 million, which was included in our Digital and Consulting Solutions segment. Included in the loss is the write-off of the cumulative translation adjustment related to Wellstream of approximately $9 million.

Mono Pumps. In January 2003, we sold our Mono Pumps business to National Oilwell, Inc. The sale price of approximately $88 million was paid with $23 million in cash and 3.2 million shares of National Oilwell, Inc. common stock, which were valued at $65 million on January 15, 2003. We recorded a gain of $36 million on the sale in the first quarter of 2003, which was included in our Drilling and Formation Evaluation segment. Included in the gain was the write-off of the cumulative translation adjustment related to Mono Pumps of approximately $5 million. In February 2003, we sold 2.5 million of our 3.2 million shares of National Oilwell, Inc. common stock for $52 million, which resulted in a gain of $2 million, and in February 2004, we sold the remaining shares for $20 million, resulting in a gain of $6 million. The gains related to the sale of the National Oilwell, Inc. common stock were recorded in “Other, net.”

Bredero-Shaw. In the second quarter of 2002, we incurred an impairment charge of $61 million related to our then-pending sale of Bredero-Shaw. On September 30, 2002, we sold our 50% interest in the Bredero-Shaw joint venture to our partner ShawCor Ltd. The sale price of $149 million was comprised of $53 million in cash, a short-term note of $25 million and 7.7 million of ShawCor Class A Subordinate shares. Consequently, we recorded a 2002 third quarter loss on the sale of $18 million, which is reflected in our Digital and Consulting Solutions segment. Included in this loss was $15 million of cumulative translation adjustment loss, which was realized upon the disposition of our investment in Bredero- Shaw. During the 2002 fourth quarter, we recorded in “Other, net” a $9 million loss on the sale of ShawCor shares.

European Marine Contractors Ltd. In January 2002, we sold our 50% interest in European Marine Contractors Ltd., an unconsolidated joint venture reported within our Digital and Consulting Solutions segment, to our joint venture partner, Saipem. At the date of sale, we received $115 million in cash and a contingent payment option valued at $16 million, resulting in a gain of $108 million. The contingent payment option was based on a formula linked to performance of the Oil Service Index. In February 2002, we exercised our option and received an additional $19 million and recorded a gain of $3 million, in “Other, net” in the statement of operations as a result of the increase in value of this option.


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Note 5. Business Segment Information

During the second quarter of 2003, we restructured our Energy Services Group into four segments, and, in the fourth quarter of 2004, we restructured KBR into two segments, which form the basis for the six segments we now report. The new segments mirror the way our chief operating decision maker now regularly reviews the operating results, assesses performance, and allocates resources.

We refer to the combination of Production Optimization, Fluid Systems, Drilling and Formation Evaluation, and Digital and Consulting Solutions segments as the Energy Services Group and the combination of our Government and Infrastructure and Energy and Chemicals segments as KBR.

The amounts in the 2003 and 2002 notes to the consolidated financial statements related to segments have been restated to conform to the 2004 composition of reportable segments.

Energy Services Group

Following is a summary of our Energy Services Group segments.

Production Optimization. The Production Optimization segment primarily tests, measures, and provides means to manage and/or improve well production once a well is drilled and, in some cases, after it has been producing. This segment consists of production enhancement services and completion tools and services.

Production enhancement services include stimulation services, pipeline process services, sand control services, coiled tubing tools and services, and hydraulic workover services. Stimulation services optimize oil and gas reservoir production through a variety of pressure pumping services and chemical processes, commonly know as fracturing and acidizing. Pipeline process services include pipeline and facility testing, commissioning, and cleaning via pressure pumping, chemical systems, specialty equipment, and nitrogen, which are provided to the midstream and downstream sectors of the energy business. Sand control services include fluid and chemical systems and pumping services for the prevention of formation sand production.

Also included in the Production Optimization segment are WellDynamics, an intelligent well completions joint venture, which was consolidated in the first quarter of 2004, and subsea operations conducted by Subsea 7, Inc., of which we formerly owned 50%.

Fluid Systems. The Fluid Systems segment focuses on providing services and technologies to assist in the drilling and construction of oil and gas wells. Drilling fluids are used to provide for well control, drilling efficiency, and as a means of removing wellbore cuttings. This segment consists of:

cementing services, which involve the process used to bond the well and well casing while isolating fluid zones and maximizing wellbore stability. Our cementing service line also provides casing equipment and services;

Baroid Fluid Services product line, which provides drilling fluid systems, performance additives, solids control and waste management services for oil and gas drilling, completion, and workover operations; and


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Enventure, which is an expandable casing joint venture. The joint venture is currently a cost method investment that was accounted for using the equity method prior to the ownership restructuring agreement with Shell in the first quarter of 2004.

Drilling and Formation Evaluation. The Drilling and Formation Evaluation segment is primarily involved in drilling and evaluating the formations related to bore-hole construction and initial oil and gas formation evaluation. The products and services in this segment incorporate integrated technologies, which offer synergies related to drilling activities and data gathering. This segment consists of:

Sperry Drilling Services, which provides drilling systems and services. These services include directional and horizontal drilling, measurement-while-drilling, logging-while-drilling, multilateral completion systems, and rig site information systems;

Security DBS Drill Bits, which provides roller cone rock bits, fixed cutter bits, and other downhole tools used in drilling oil and gas wells; and

logging services, which include open-hole wireline services that provide information on formation evaluation. Also offered are cased-hole services and magnetic resonance imaging tools.

Digital and Consulting Solutions. The Digital and Consulting Solutions segment provides integrated exploration and production software information systems, consulting services, real-time operations, subsea operations, value-added oilfield project management, and other integrated solutions. Included in this business segment is Landmark Graphics, a supplier of integrated exploration and production software information systems, as well as professional and data management services. Also included were Wellstream, Bredero-Shaw, and European Marine Contractors Ltd., all of which have been sold.

KBR

KBR provides engineering, procurement, construction, project management, and facilities operation and maintenance for oil and gas and other industrial customers and government entities worldwide. Following is a summary of KBR’s segments.

Government and Infrastructure. The Government and Infrastructure segment is one of the largest government logistics and services contractors with worldwide civil infrastructure capabilities. This segment represents construction, maintenance, and logistics services for government operations, facilities, and installations. Other major operations include civil engineering, consulting, project management services for state and local governments and private industries, integrated security solutions, dockyard operation and maintenance through the Devonport Royal Dockyard Limited (DML) subsidiary, and privately financed initiatives.

Energy and Chemicals. The Energy and Chemicals segment is a global engineering, procurement, construction, technology, and services provider for the energy and chemicals industries. Working both upstream and downstream in support of our customers, Energy and Chemicals offers the following:

upstream deepwater engineering, marine technology, and project management;

plant operations, maintenance, and start-up services for both upstream and downstream oil, gas, and petrochemical facilities, as well as operations, maintenance, and logistics services for the power, commercial, and industrial markets;

industry-leading licensed technologies in the areas of fertilizers and synthesis gas, olefins, refining, and chemicals and polymers; and


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consulting services in the form of expert technical and management advice covering studies, conceptual and detailed engineering, project management, construction supervision and design, and construction verification or certification in both upstream and downstream markets.

General corporate. General corporate represents assets not included in a business segment and is primarily composed of cash and cash equivalents, deferred tax assets, and insurance for asbestos and silica litigation claims.

Intersegment revenue and revenue between geographic areas are immaterial. Our equity in pretax earnings and losses of unconsolidated affiliates that are accounted for on the equity method is included in revenue and operating income of the applicable segment.

Total revenue for 2004 includes $8.0 billion, or 39% of consolidated revenue from the United States Government, and total revenue for 2003 includes $4.2 billion, or 26% of consolidated revenue from the United States Government, which is derived almost entirely from our Government and Infrastructure segment. Revenue from the United States Government during 2002 represented less than 10% of consolidated revenue. No other customer represented more than 10% of consolidated revenue in any period presented.


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The tables below present information on our business segments.

*Operations by Business Segment*
	Years ended December 31
Millions of dollars	2004			2003			2002
Revenue:
Production Optimization	$	3,303		$	2,758		$	2,544
Fluid Systems		2,324			2,039			1,815
Drilling and Formation Evaluation		1,782			1,643			1,633
Digital and Consulting Solutions		589			555			844
Total Energy Services Group		7,998			6,995			6,836
Government and Infrastructure		9,393			5,417			1,539
Energy and Chemicals		3,075			3,859			4,197
Total KBR		12,468			9,276			5,736
Total	$	20,466		$	16,271		$	12,572
Operating income (loss):
Production Optimization	$	633		$	413		$	374
Fluid Systems		348			251			202
Drilling and Formation Evaluation		225			177			160
Digital and Consulting Solutions		60			(15	)		(98	)
Total Energy Services Group		1,266			826			638
Government and Infrastructure		84			194			75
Energy and Chemicals		(426	)		(225	)		(131	)
Shared KBR		-			(5	)		(629	)
Total KBR		(342	)		(36	)		(685	)
General corporate		(87	)		(70	)		(65	)
Total	$	837		$	720		$	(112	)
Capital expenditures:
Production Optimization	$	181		$	124		$	118
Fluid Systems		66			54			55
Drilling and Formation Evaluation		135			145			190
Digital and Consulting Solutions		32			27			149
Shared energy services		84			103			91
Total Energy Services Group		498			453			603
Government and Infrastructure		41			45			138
Energy and Chemicals		9			5			12
Shared KBR		27			12			11
Total KBR		77			62			161
Total	$	575		$	515		$	764

Within the Energy Services Group and KBR, not all assets are associated with specific segments. Those assets specific to segments include receivables, inventories, certain identified property, plant, and equipment (including field service equipment), equity in and advances to related companies, and goodwill. The remaining assets, such as cash and the remaining property, plant, and equipment (including shared facilities) are considered to be shared among the segments within the two groups. For segment operating income presentation, the depreciation expense associated with these shared Energy Services Group assets and KBR assets are allocated to the two groups and general corporate.


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Revenue by country is determined based on the location of services provided and products sold.

*Operations by Business Segment (continued)*
	Years ended December 31
Millions of dollars	2004		2003		2002
Depreciation, depletion, and amortization:
Production Optimization	$	115	$	104	$	99
Fluid Systems		60		50		48
Drilling and Formation Evaluation		115		144		137
Digital and Consulting Solutions		75		77		112
Shared energy services		91		92		79
Total Energy Services Group		456		467		475
Government and Infrastructure		27		22		11
Energy and Chemicals		11		16		17
Shared KBR		15		12		1
Total KBR		53		50		29
General corporate		-		1		1
Total	$	509	$	518	$	505
Total assets:
Production Optimization	$	1,754	$	1,659	$	1,444
Fluid Systems		1,045		1,030		830
Drilling and Formation Evaluation		960		1,074		1,163
Digital and Consulting Solutions		768		794		1,320
Shared energy services		1,021		1,240		1,187
Total Energy Services Group		5,548		5,797		5,944
Government and Infrastructure		3,309		2,758		784
Energy and Chemicals		1,656		2,078		2,055
Shared KBR		198		246		265
Total KBR		5,163		5,082		3,104
General corporate		5,085		4,620		3,796
Total	$	15,796	$	15,499	$	12,844

*Operations by Geographic Area*
	Years ended December 31
Millions of dollars	2004		2003		2002
Revenue:
Iraq	$	5,362	$	2,399	$	1
United States		4,461		4,415		4,139
Kuwait		1,841		856		50
United Kingdom		1,646		1,473		1,521
Other countries		7,156		7,128		6,861
Total	$	20,466	$	16,271	$	12,572
Long-lived assets:
United States	$	2,485	$	4,461	$	4,617
United Kingdom		697		630		691
Other countries		1,126		917		711
Total	$	4,308	$	6,008	$	6,019


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Note 6. Receivables (Other than “Insurance for asbestos- and silica-related liabilities”)

Our receivables are generally not collateralized. Included in notes and accounts receivable are notes with varying interest rates totaling $12 million at December 31, 2004 and $11 million at December 31, 2003. At December 31, 2004, 39% of our consolidated receivables related to our United States government contracts, primarily for projects in the Middle East. Receivables from the United States government at December 31, 2003 represented 41% of consolidated receivables.

Under an agreement to sell United States Energy Services Group accounts receivable to a bankruptcy-remote limited-purpose funding subsidiary, new receivables are added on a continuous basis to the pool of receivables. Collections reduce previously sold accounts receivable. This funding subsidiary sells an undivided ownership interest in this pool of receivables to entities managed by unaffiliated financial institutions under another agreement. Sales to the funding subsidiary have been structured as “true sales” under applicable bankruptcy laws. While the funding subsidiary is wholly owned by us, its assets are not available to pay any creditors of ours or of our subsidiaries or affiliates. The undivided ownership interest in the pool of receivables sold to the unaffiliated companies, therefore, is reflec ted as a reduction of accounts receivable in our consolidated balance sheets. The funding subsidiary retains the interest in the pool of receivables that are not sold to the unaffiliated companies and is fully consolidated and reported in our financial statements.

The amount of undivided interests which can be sold under the program varies based on the amount of eligible Energy Services Group receivables in the pool at any given time and other factors. The maximum amount that may be sold and outstanding under this agreement at any given time is $300 million. As of December 31, 2004, we had sold $256 million undivided ownership interest to unaffiliated companies. The securitization facility matures in April 2005.

In May 2004, we entered into an agreement to sell, assign, and transfer the entire title and interest in specified United States government accounts receivable of KBR to a third party. The face value of the receivables sold to the third party is reflected as a reduction of accounts receivable in our consolidated balance sheets. The amount of receivables which can be sold under the agreement varies based on the amount of eligible receivables at any given time and other factors, and the maximum amount that may be sold and outstanding under this agreement at any given time is $650 million. The total amount of receivables outstanding under this agreement as of December 31, 2004 was approximately $263 million. Subsequent to December 31, 2004, these receivables were collected and the balance retired, and we are not curr ently selling receivables, although the facility continues to be available.

Note 7. Inventories

Inventories are stated at the lower of cost or market. We manufacture in the United States certain finished products and parts inventories for drill bits, completion products, bulk materials, and other tools that are recorded using the last-in, first-out method totaling $37 million at December 31, 2004 and $38 million at December 31, 2003. If the average cost method had been used, total inventories would have been $17 million higher than reported at both December 31, 2004 and at December 31, 2003. The cost of over 95% of the remaining inventory is recorded on the average cost method, with the remainder on the first-in, first-out method. Inventories at December 31, 2004 and December 31, 2003 were composed of the following:

	December 31
Millions of dollars	2004		2003
Finished products and parts	$	534	$	503
Raw materials and supplies		156		159
Work in process		33		33
Total	$	723	$	695


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Finished products and parts are reported net of obsolescence reserves of $119 million at December 31, 2004 and $117 million at December 31, 2003.

Note 8. Restricted Cash

At December 31, 2004, we had restricted cash of $138 million, which consists of:

$98 million as collateral for potential future insurance claim reimbursements, included in “Other assets”;

$36 million ($23 million in “Other assets” and $13 million in “Other current assets”) primarily related to cash collateral agreements for outstanding letters of credit for various construction projects; and

$4 million for payroll related to bankruptcy, which was released in January 2005.

At December 31, 2003, we had restricted cash of $159 million in “Other current assets” and $100 million in “Other assets,” which consisted of similar items as above. Included in these amounts were $107 million that collateralized a bond for a patent infringement judgment on appeal and $37 million related to the Chapter 11 proceedings.

Note 9. Property, Plant, and Equipment

Property, plant, and equipment at December 31, 2004 and 2003 are composed of the following:

Millions of dollars	2004		2003
Land	$	68	$	80
Buildings and property improvements		1,088		1,065
Machinery, equipment, and other		5,071		4,921
Total		6,227		6,066
Less accumulated depreciation		3,674		3,540
Net property, plant, and equipment	$	2,553	$	2,526

Machinery, equipment, and other includes oil and gas properties of $308 million at December 31, 2004 and $359 million at December 31, 2003.

The percentage of total building and property improvements and total machinery, equipment, and other, excluding oil and gas investments, are depreciated over the following useful lives:

	Building and Property
	Improvements
	2004			2003
1 - 10 years		19	%		19	%
11 - 20 years		45	%		48	%
21 - 30 years		16	%		12	%
31 - 40 years		20	%		21	%

	Machinery, Equipment,
	and Other
	2004			2003
1 - 5 years		28	%		30	%
6 - 10 years		63	%		62	%
11 - 25 years		9	%		8	%


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In the second quarter of 2004, we implemented a change in accounting estimate to more accurately reflect the useful life of some of the tools of our Drilling and Formation Evaluation segment. This resulted in a combined $35 million reduction in depreciation expense in the last three quarters of 2004, thereby reducing our consolidated net loss by $22 million, or $0.05 per share, for 2004. We extended the useful lives of these tools based on our review of their service lives, technological improvements in the tools, and recent changes to our repair and maintenance practices which helped to extend the lives.

Note 10. Debt

Short-term notes payable of $15 million at December 31, 2004 and $18 million at December 31, 2003 are included in “Other current liabilities” in the consolidated balance sheets. Long-term debt at December 31, 2004 and 2003 consisted of the following:

Millions of dollars	2004		2003
3.125% convertible senior notes due July 2023	$	1,200	$	1,200
0.75% plus three-month LIBOR senior notes
due January 2007		500		-
5.5% senior notes due October 2010		748		748
1.5% plus three-month LIBOR senior notes
due October 2005		300		300
Medium-term notes due 2006 through 2027		600		600
7.6% debentures of Halliburton due August 2096		294		294
8.75% debentures due February 2021		200		200
Other		98		95
Total long-term debt		3,940		3,437
Less current portion		347		22
Noncurrent portion of long-term debt	$	3,593	$	3,415

Convertible notes. In June 2003, we issued $1.2 billion of 3.125% convertible senior notes due July 15, 2023, with interest payable semiannually. The notes are our senior unsecured obligations ranking equally with all of our existing and future senior unsecured indebtedness.

The notes are convertible under any of the following circumstances:

during any calendar quarter if the last reported sale price of our common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the previous quarter is greater than or equal to 120% of the conversion price per share of our common stock on such last trading day;

if the notes have been called for redemption;

upon the occurrence of specified corporate transactions that are described in the indenture relating to the offering; or

during any period in which the credit ratings assigned to the notes by both Moody’s Investors Service and Standard & Poor’s are lower than Ba1 and BB+, respectively, or the notes are no longer rated by at least one of these rating services or their successors.

The initial conversion price is $37.65 per share and is subject to adjustment upon the occurrence of a stock dividends in common stock, the issuance of rights or warrants, stock splits and combinations, the distribution of indebtedness, securities, or assets, or excess cash distributions.

Upon conversion, we must settle the principal amount of the notes in cash, and for any amounts in excess of the aggregate principal we have the right to deliver shares of our common stock, cash, or a combination of cash and common stock.


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See Note 17 for discussion of supplemental indenture on these notes.

The notes are redeemable for cash at our option on or after July 15, 2008. Holders may require us to repurchase the notes for cash on July 15 of 2008, 2013, or 2018 or, prior to July 15, 2008, in the event of a fundamental change as defined in the underlying indenture.

Senior notes due 2007. In January 2004, we issued $500 million aggregate principal amount of senior notes due 2007 bearing interest at a floating rate equal to three-month LIBOR (London interbank offered rates) plus 0.75%, payable quarterly. We have the option to redeem all or a portion of the outstanding notes on any quarterly interest payment date.

Floating- and fixed-rate senior notes. In October 2003, we completed an offering of $1.05 billion of floating and fixed-rate unsecured senior notes. The fixed-rate notes, with an aggregate principal amount of $750 million, will mature on October 15, 2010 and bear interest at a rate equal to 5.5%, payable semiannually. The fixed-rate notes were initially offered on a discounted basis at 99.679% of their face value. The discount is being amortized to interest expense over the life of the bond. The floating-rate notes, with an aggregate principal amount of $300 million, will mature on October 17, 2005 and bear interest at a rate equal to three-month LIBOR plus 1.5%, payable quarterly.

Medium-term notes. We have outstanding notes under our medium-term note program as follows:

Due	Rate			Amount (in millions)
08/2006		6.00	%	$	275
12/2008		5.63	%	$	150
05/2017		7.53	%	$	50
02/2027		6.75	%	$	125

We may redeem the 6.00% and 5.63% medium-term notes in whole or in part at any time. The 7.53% notes may not be redeemed prior to maturity. Each holder of the 6.75% medium-term notes has the right to require us to repay their notes in whole or in part on February 1, 2007. The medium-term notes do not have sinking fund requirements and rank equally with our existing and future senior unsecured indebtedness.

Revolving credit facilities. As of December 31, 2004 we had outstanding, for general working capital purposes:

a $700 million revolving credit facility, which expires in October 2006; and

a $500 million 364-day revolving credit facility, which expires in July 2005.

In September 2004, we issued a letter of credit for approximately $172 million under our $700 million revolving credit facility to replace an expiring letter of credit for our Barracuda-Caratinga project, which reduced our availability under the revolving credit facility to $528 million. As of December 31, 2004, no cash had been drawn under either revolving credit facility.

Borrowings under the revolving credit facilities will be secured by certain of our assets until our long-term senior unsecured debt is rated BBB or higher (stable outlook) by Standard & Poor’s and Baa2 or higher (stable outlook) by Moody’s Investors Service.


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100% of the stock of Halliburton Energy Services, Inc. (a wholly owned subsidiary of Halliburton);

100% of the stock or other equity interests held by Halliburton and Halliburton Energy Services, Inc. in certain of their first-tier domestic subsidiaries;

66% of the stock or other equity interests of Halliburton Affiliates LLC (a wholly owned subsidiary of Halliburton); and

66% of the stock or other equity interests of certain foreign subsidiaries of Halliburton or Halliburton Energy Services, Inc.

As of December 31, 2004, we had approximately $50 million of secured debt outstanding.

Maturities. Our debt, excluding the effects of our terminated interest rate swaps, matures as follows: $347 million in 2005; $293 million in 2006; $518 million in 2007; $156 million in 2008; zero in 2009; and $2,625 million thereafter.

Note 11. Asbestos and Silica Obligations and Insurance Recoveries

Summary

Several of our subsidiaries, particularly DII Industries and Kellogg Brown & Root, had been named as defendants in a large number of asbestos- and silica-related lawsuits. The plaintiffs alleged injury primarily as a result of exposure to:

asbestos used in products manufactured or sold by former divisions of DII Industries (primarily refractory materials, gaskets, and packing materials used in pumps and other industrial products);

asbestos in materials used in the construction and maintenance projects of Kellogg Brown & Root or its subsidiaries; and

silica related to sandblasting and drilling fluids operations.

Effective December 31, 2004, we resolved all open and future claims in the prepackaged Chapter 11 proceedings of DII Industries, Kellogg Brown & Root, and our other affected subsidiaries (which were filed on December 16, 2003) upon the District Court’s affirmation order and the bankruptcy court’s order confirming the plan of reorganization becoming final and nonappealable. In January 2005, we paid approximately $2.3 billion in cash and transferred 59.5 million shares of our common stock to the trusts established for the benefit of asbestos and silica claimants. The first table that follows summarizes the various charges we have incurred during 2002, 2003, and 2004. The second table presents a rollforward of our asbestos- and silica-related liabilities and insurance receivables.


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	2004					2003					2002
	Continuing		Discontinued			Continuing			Discontinued		Continuing			Discontinued
Millions of dollars	Operations		Operations			Operations			Operations		Operations			Operations
Asbestos and silica charges:
Prepackaged Chapter 11
proceedings	$	-	$	-		$	-		$	1,016	$	-		$	-
2002 Rabinovitz Study		-		-			-			-		564			2,256
59.5 million share revaluation		-		778			-			-		-			-
Federal-Mogul partitioning
agreement		-		44			-			-		-			-
Revaluation of silica note		-		3			-			-		-			-
Subtotal		-		825			-			1,016		564			2,256
Asbestos and silica
insurance write-off
(receivables):
Insurance receivable write-
down		-		698			-			-		-			-
Navigant Study		-		-			-			6		-			(1,530	)
Write-off of Highlands
accounts receivable		-		-			-			-		80			-
Subtotal		-		698			-			6		80			(1,530	)
Other costs:
Harbison-Walker matters		-		-			-			51		-			45
Professional fees		-		28			-			58		-			35
Cash in lieu of interest		-		7			-			24		-			-
Accretion		-		(22	)		-			-		-			-
Other costs		-		4			5			-		-			-
Subtotal		-		17			5			133		-			80
Pretax asbestos and silica
charges		-		1,540			5			1,155		644			806
Tax provision (benefit)		-		(179	)		(2	)		5		(114	)		(154	)
Total asbestos and silica
charges, net of tax	$	-	$	1,361		$	3		$	1,160	$	530		$	652

	December 31
Millions of dollars	2004			2003
Asbestos and silica related liabilities:
Beginning balance	$	4,086		$	3,425
Accrued liability		-			1,016
59.5 million shares revaluation		778			-
Federal-Mogul partitioning agreement		44			-
Revaluation of silica note		3			-
Payments on claims		(119	)		(355	)
Reclassification of 59.5 million shares to
shareholders’ equity		(2,335	)		-
Other		(12	)		-
Asbestos and silica related liabilities - ending balance
(of which $2,408 and $2,507 is current)	$	2,445		$	4,086
Insurance for asbestos and silica related liabilities:
Beginning balance	$	(2,134	)	$	(2,103	)
Write-off of insurance recoveries/net present
value true-up		698			6
Accretion		(22	)		-
Purchase of Harbison-Walker receivable,
net of allowance		-			(40	)
Payments received		37			3
Other		5			-
Insurance for asbestos and silica related liabilities -
ending balance (of which $1,066 and $96 is current)	$	(1,416	)	$	(2,134	)


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Prepackaged Chapter 11 proceedings and insurance settlements

Prepackaged Chapter 11 proceedings. DII Industries, Kellogg Brown & Root, and six other subsidiaries (Mid-Valley, Inc.; KBR Technical Services, Inc.; Kellogg Brown & Root Engineering Corporation; Kellogg Brown & Root International, Inc. (a Delaware corporation); Kellogg Brown & Root International, Inc. (a Panamanian corporation); and BPM Minerals, LLC) filed Chapter 11 proceedings on December 16, 2003 in bankruptcy court in Pittsburgh, Pennsylvania. Each of these entities was a wholly owned subsidiary of Halliburton before, during, and after the bankruptcy proceedings became final.

Our subsidiaries sought Chapter 11 protection to avail themselves of the provisions of Sections 524(g) and 105 of the Bankruptcy Code to discharge current and future asbestos and silica personal injury claims against us and our subsidiaries. The order confirming the plan of reorganization became final and nonappealable on December 31, 2004 and the plan of reorganization became effective in January 2005. Under the plan of reorganization all current and future asbestos and silica personal injury claims against us and our affiliates were channeled into trusts established for the benefit of asbestos and silica claimants, thus releasing us from those claims.

In accordance with the plan of reorganization, in January 2005 we contributed the following to trusts for the benefit of current and future asbestos and silica personal injury claimants:

approximately $2.345 billion in cash, which represents the remaining portion of the $2.775 billion total cash settlement after payments of $311 million in December 2003 and $119 million in June 2004;

59.5 million shares of Halliburton common stock;

As a result of the filing of the Chapter 11 proceedings, we adjusted the asbestos and silica liability to reflect the full amount of the proposed settlement and certain related costs, which resulted in a pretax charge of approximately $1.016 billion to discontinued operations in the fourth quarter of 2003. The tax effect on this charge was minimal, as a valuation allowance was established against the liability to reflect the expected net tax benefit from the future deductions the liability will create.

In accordance with the definitive settlement agreements entered in early 2003, we reviewed plaintiff files to establish a medical basis for payment of settlement amounts and to establish that the claimed injuries were based on exposure to our products. In 2003, we concluded that substantially all of the asbestos and silica liability related to claims filed against our former operations that have been divested and included in discontinued operations. Consequently, all 2003 and 2004 changes in our estimates related to the asbestos and silica liability were recorded through discontinued operations.


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shareholders’ equity the final value of the 59.5 million shares of Halliburton common stock. If the shares had been included in the calculation of earnings per share as of the beginning of 2004, our diluted earnings per share from continuing operations would have been reduced by $0.11 for 2004.

Insurance settlements. During 2004, we settled insurance disputes with substantially all the insurance companies for asbestos- and silica-related claims and all other claims under the applicable insurance policies and terminated all the applicable insurance policies. Under the terms of our insurance settlements, we will receive cash proceeds with a nominal amount of approximately $1.5 billion and with a present value of approximately $1.4 billion for our asbestos- and silica-related insurance receivables. The present value was determined by discounting the expected future cash payments with a discount rate implicit in the settlements, which ranged from 4.0% to 5.5%. Beginning in the third quarter of 2004, this disco unt is being accreted as interest income (classified as discontinued operations) over the life of the expected future cash payments. Cash payments of approximately $1 billion related to these receivables were received in January 2005. Under the terms of the settlement agreements, we will receive cash payments of the remaining amounts in several installments beginning in July 2005 through 2009.

A significant portion of the insurance coverage applicable to Worthington Pump, a former division of DII Industries, was alleged by Federal-Mogul (and others who formerly were associated with Worthington Pump prior to its acquisition by DII Industries) to be shared with them. During 2004, we reached an agreement with Federal-Mogul, our insurance companies, and another party sharing in the insurance coverage to obtain their consent and support of a partitioning of the insurance policies. Under the terms of the agreement, DII Industries was allocated 50% of the limits of any applicable insurance policy, and the remaining 50% of limits of the insurance policies were allocated to the remaining policyholders. As part of the settlement, DII Industries agreed to pay $46 million in three installment payments. The first pa yment of $16 million was paid in January 2005. The second and third payments of $15 million each will occur on the first and second anniversaries from the date of the first payment. In 2004, we accrued $44 million, which represents the present value of the $46 million to be paid. The discount is accreted as interest expense (classified as discontinued operations) over the life of the expected future cash payments beginning in the fourth quarter of 2004.

DII Industries and Federal-Mogul agreed to share equally in recoveries from insolvent London-based insurance companies. To the extent that Federal-Mogul’s recoveries from certain insolvent London-based insurance companies received on or before January 1, 2006 do not equal at least $4.5 million, DII Industries agreed to also pay to Federal-Mogul the difference between their recoveries from the insolvent London-based insurance companies and $4.5 million. Any recoveries received by Federal-Mogul from the insolvent London-based insurance companies after January 1, 2006 will be reimbursed to DII Industries until such time as DII Industries is fully reimbursed for the amount of the payment.

Under the insurance settlements entered into as part of the resolution of our Chapter 11 proceedings, we have agreed to indemnify our insurers under certain historic general liability insurance policies in certain situations. The following factors were considered when entering into these indemnifications:

we conducted an extensive due diligence process to determine if other third parties have rights to assert claims under the relevant insurance policies. Any third parties known to us which we determined might have rights allowing them to assert claims under these insurance policies have either waived their rights to assert claims under the insurance


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policies or have been excluded from the scope of the indemnities. Therefore, we are not aware of any third parties that could assert valid claims under the relevant insurance policies that could trigger our indemnification obligations;

the settlements that we have entered into with our insurers have exhausted the relevant products limits of liability applicable to asbestos, silica and other product claims. These settlements have been approved by the bankruptcy court as reasonable, good faith settlements;

the insurance policies that are subject to the indemnity were issued for 1992 and prior periods. If there is an undiscovered third party that can assert a valid, covered claim under the relevant policies that has not already had such claims excluded from the scope of the indemnity, any claims asserted would be at least 12 years old. Moreover, given the exclusions that appear in the insurance policies beginning in 1985 and, in some cases 1971, the probable age of any claim that could potentially trigger our indemnity obligations is almost 20 years old. Given this passage of time, which passage of time also gives rise to defenses to coverage under the relevant insurance policies, such as late notice defenses, and the lack of any known third party that could assert a claim that could trigger our indemnity obligations, we believe that the likelihood of any third party being able to assert claims that could trigger our indemnity is remote.

Accordingly, we have concluded that the likelihood of any claims triggering the indemnity obligations is remote, and we believe any potential liability for these indemnifications will be immaterial.

At December 31, 2004, we had not recorded any liability associated with these indemnifications.

Other matters relating to 2003 and 2002

Harbison-Walker Chapter 11 proceedings. A large portion of our asbestos claims related to alleged injuries from asbestos used in a small number of products manufactured or sold by Harbison-Walker Refractories Company, whose operations DII Industries acquired in 1967 and spun off in 1992. At the time of the spin-off, Harbison-Walker assumed liability for asbestos claims filed after the spin-off, and it agreed to defend and indemnify DII Industries from liability for those claims, although DII Industries continued to have direct liability to tort claimants for all post-spin-off refractory asbestos claims. DII Industries retained responsibility for all asbestos claims pending as of the date of the spin-off. The agreeme nt governing the spin-off provided that Harbison-Walker would have the right to access DII Industries’ historic insurance coverage for the asbestos-related liabilities that Harbison-Walker assumed in the spin-off.

In July 2001, DII Industries determined that the demands that Harbison-Walker was making on the shared insurance policies were not acceptable to DII Industries and that Harbison-Walker probably would not be able to fulfill its indemnification obligations to DII Industries. Accordingly, DII Industries took up the defense of unsettled post-spin-off refractory claims that name it as a defendant in order to prevent Harbison-Walker from unnecessarily eroding the insurance coverage both companies access for these claims.

In February 2002, Harbison-Walker filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code. In its initial Chapter 11 filings, Harbison-Walker stated it would seek to utilize Sections 524(g) and 105 of the Bankruptcy Code to propose and seek confirmation of a plan of reorganization that would provide for distributions for all legitimate pending and future asbestos and silica claims asserted directly against Harbison-Walker or asserted against DII Industries. In order to protect the shared insurance from dissipation, DII Industries began to assist Harbison-Walker in its Chapter 11 proceedings as follows:

in February 2002, DII Industries paid $40 million to Harbison-Walker’s United States parent holding company, RHI Refractories Holding Company (RHI Refractories);


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DII Industries agreed to provide up to $35 million in debtor-in-possession financing to Harbison-Walker ($5 million was paid in 2002 and the remaining $30 million was paid in 2003); and

during 2003, DII Industries purchased $50 million of Harbison-Walker’s outstanding insurance receivables, of which $10 million were estimated to be uncollectible. These receivables were included as part of the insurance settlements.

All the cash payments noted above ($40 million paid in February 2002, $5 million paid in 2002 and $30 million paid in 2003) and $10 million write-off of Harbison-Walker insurance receivable are included in the asbestos and silica charges table in the appropriate years under the line item “Harbison-Walker matters.”

In 2003, DII Industries entered into a definitive agreement with Harbison-Walker. Under the terms of this agreement, once our plan of reorganization became final, all asbestos and silica personal injury claims against Harbison-Walker and certain of its affiliates were channeled into trusts created in our bankruptcy proceedings. Our asbestos and silica obligations and related insurance recoveries recorded as of December 31, 2003 and 2004 reflected the terms of this definitive agreement.

In the first quarter of 2004, we entered into an agreement with RHI Refractories to settle remaining funding issues relating to Harbison-Walker. The agreement calls for a $10 million payment to RHI Refractories and a $1 million payment to our asbestos and silica trusts on behalf of RHI Refractories. These amounts were expensed during 2003 and are include in the asbestos and silica charges table under line item “Harbison-Walker matters”. These payments were made during January 2005.

Highlands litigation. Highlands Insurance Company (Highlands) was our wholly-owned insurance company until it was spun off to our shareholders in 1996. Highlands wrote the primary insurance coverage for the construction claims related to Brown & Root, Inc. prior to 1980. In March 2002, Highlands won a lawsuit against Halliburton asserting that the construction claims insurance it wrote for Brown & Root, Inc. was terminated by agreements between Halliburton and Highlands at the time of the 1996 spin-off. As a result of this ruling, in the first quarter 2002 we wrote off approximately $35 million in accounts receivable for amounts paid for claims and defense costs and $45 million of accrued receivables in rela tion to estimated insurance recoveries claims settlements from Highlands.

Other. We continue to pursue our insurance rights against certain insolvent London-based and domestic insurance companies, such as Highlands Insurance Company (under insurance policies that were issued to Dresser Industries, Inc. and certain of its predecessors) and The Home Insurance Company.

Asbestos and silica obligations and receivables based upon outside studies

Rabinovitz study. In late 2001, DII Industries retained Dr. Francine F. Rabinovitz of Hamilton, Rabinovitz & Alschuler, Inc. to estimate the probable number and value, including defense costs, of unresolved current and future asbestos and silica-related bodily injury claims asserted against DII Industries and its subsidiaries. Dr. Rabinovitz’s estimates are based on historical data supplied by us and publicly available studies, including annual surveys by the National Institutes of Health concerning the incidence of mesothelioma deaths. In addition, Dr. Rabinovitz used the following assumptions in her estimates:

there will be no legislative or other systemic changes to the tort system;

we will continue to aggressively defend against asbestos claims made against us;

an inflation rate of 3% annually for settlement payments and an inflation rate of 4% annually for defense costs; and

we would receive no relief from our asbestos obligation due to actions taken in the Harbison-Walker Chapter 11 proceedings.

In her estimates, Dr. Rabinovitz relied on the source data provided by our management; she did not independently verify the accuracy of the source data. The report took approximately seven months to complete.


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Dr. Rabinovitz estimated the current and future total undiscounted liability for personal injury asbestos and silica claims through 2052, including defense costs, would be a range between $2.2 billion and $3.5 billion. The lower end of the range was calculated by using an average of the last five years of asbestos claims experience and the upper end of the range was calculated using the more recent two-year elevated rate of asbestos claim filings in projecting the rate of future claims. As a result of reaching an agreement in principle in December of 2002 (which was the basis of the definitive settlement agreements entered in early 2003) for the settlement of all of our asbestos and silica claims, we believed it was appropriate to adjust our accrual to use the upper end of the range contained in Dr. Rabinovitz 6;s study. Therefore, in 2002, we recorded a pretax charge of $2.820 billion to increase our asbestos and silica liability to the upper end of the range.

Navigant studies. In 2002, we retained Navigant Consulting (formerly Peterson Consulting), a nationally recognized consultant in asbestos and silica liability and insurance, to work with us to project the amount of insurance recoveries probable at that time. In conducting this analysis, Navigant Consulting used the Rabinovitz Study to project liabilities through 2052 using the two-year elevated rate of asbestos claim filings. The methodology used by Navigant Consulting for that study was consistent with the methodology employed in December 2003. Based on our analysis of the probable insurance recoveries, we recorded a receivable of $1.530 billion.

In December 2003, we again retained Navigant Consulting to assist us. In conducting their analysis, Navigant Consulting performed the following with respect to our policies:

reviewed DII Industries’ historical course of dealings with its insurance companies concerning the payment of asbestos-related claims, including DII Industries’ 15-year litigation and settlement history;

reviewed our insurance coverage policy database containing information on key policy terms as provided by outside counsel;

reviewed the terms of DII Industries’ prior and current coverage-in-place settlement agreements;

reviewed the status of DII Industries’ and Kellogg Brown & Root’s current insurance-related lawsuits and the various legal positions of the parties in those lawsuits in relation to the developed and developing case law and the historic positions taken by insurers in the earlier filed and settled lawsuits;

engaged in discussions with our counsel; and

analyzed publicly available information concerning the ability of the DII Industries insurers to meet their obligations.

Navigant Consulting’s analysis assumed that there would be no recoveries from insolvent carriers and that those carriers which are currently solvent would continue to be solvent throughout the period of the applicable recoveries in the projections. Based on its review, analysis and discussions, Navigant Consulting’s analysis assisted us in making our judgments concerning insurance coverage that we believed were reasonable and consistent with our historical course of dealings with our insurers and the relevant case law to determine the probable insurance recoveries for asbestos liabilities. This analysis included the probable effects of self-insurance features, such as self-insured retentions, policy exclusions, liability caps and the financial status of applicable insurers, and various judicial determina tions relevant to the applicable insurance programs. The analysis of Navigant Consulting was based on information provided by us.

As of December 31, 2003, we developed our best estimate of the asbestos and silica insurance receivables as follows:

included $575 million of insurance recoveries from Equitas based on a January 2004 comprehensive agreement;

included insurance recoveries from other specific insurers with whom we had settled;


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estimated insurance recoveries from specific insurers that we are probable of settling with and for which we could reasonably estimate the amount of the settlement. When appropriate, these estimates considered prior settlements with insurers with similar facts and circumstances; and

estimated insurance recoveries for all other policies with the assistance of the Navigant Consulting study.

The estimate we developed as a result of this process was consistent with the amount of asbestos and silica receivables recorded as of December 31, 2003, causing us not to significantly adjust our recorded insurance asset at that time.

Note 12. United States Government Contract Work

Fuel. In December 2003, the DCAA issued a preliminary audit report that alleged that we may have overcharged the Department of Defense by $61 million in importing fuel into Iraq. The DCAA questioned costs associated with fuel purchases made in Kuwait that were more expensive than buying and transporting fuel from Turkey. We responded that we had maintained close coordination of the fuel mission with the Army Corps of Engineers (COE), which was our customer and oversaw the project, throughout the life of the task order and that the COE had directed us to use the Kuwait sources. After a review, the COE concluded that we obtained a fair price for the fuel. However, Department of Defense officials there after referred the matter to the agency’s inspector general, which we understand commenced an investigation.

Investigations. On January 22, 2004, we announced the identification by our internal audit function of a potential overbilling of approximately $6 million by La Nouvelle Trading & Contracting Company, W.L.L. (La Nouvelle), one of our subcontractors, under the LogCAP contract in Iraq, for services performed during 2003. In accordance with our policy and government regulation, the potential overcharge was reported to the Department of Defense Inspector General's office


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as well as to our customer, the AMC. On January 23, 2004, we issued a check in the amount of $6 million to the AMC to cover that potential overbilling while we conducted our own investigation into the matter. Later in the first quarter of 2004, we determined that the amount of overbilling was $4 million, and the subcontractor billing should have been $2 million for the services provided. As a result, we paid La Nouvelle $2 million and billed our customer that amount. We subsequently terminated La Nouvelle’s services under the LogCAP contract. In October 2004, La Nouvelle filed suit against us alleging $224 million in damages as a result of its termination. We are continuing to investigate whether La Nouvelle paid, or attempted to pay, one or two of our former employees in connection with the billing.

Dining Facility and Administration Centers (DFACs). During 2003, the DCAA raised issues relating to our invoicing to the Army Materiel Command (AMC) for food services for soldiers and supporting civilian personnel in Iraq and Kuwait. We believe the issues raised by the DCAA relate to the difference between the number of troops the AMC directed us to support and the number of soldiers counted at dining facilities for United States troops and supporting civilian personnel. In the first quarter of 2004, we reviewed our DFAC subcontracts in our Iraq and Kuwait areas of operation and have billed and continue to bill for all current DFAC costs. During 2004, we received notice from the DCAA that it was rec ommending withholding a portion of our DFAC billings. For DFAC billings relating to subcontracts entered into prior to February 2004, the DCAA has recommended withholding 19.35% of the billings until it completes its audits. Subsequent to February 2004, we renegotiated our DFAC subcontracts to address the specific issues raised by the DCAA and advised the AMC and the DCAA of the new terms of the arrangements. We have had no objection by the government to the terms and conditions associated with these new DFAC subcontract agreements. During the third quarter of 2004, we received notification that, for three Kuwait DFACs, the DCAA recommended to our customer that costs be disallowed because the DCAA is not satisfied with the level of documentation provided by us. The amount withheld related to suspended and recommended disallowed DFAC costs for work performed prior to February 2004 and totaled approximately $224 million as of December 31, 2004. The amount withheld could change as the DCAA continues their audit s of the remaining DFAC facilities. We are negotiating with our customer, the AMC, to resolve this issue. We are currently withholding a proportionate amount of these billings from our subcontractors.

Laundry. During the third quarter of 2004, we received notice from the DCAA that it recommended withholding $16 million of subcontract costs related to the laundry service for one task order in southern Iraq for which it believes we and our subcontractors have not provided adequate levels of documentation supporting the quantity of the services provided. The DCAA recommended that the cost be withheld pending receipt of additional explanation or


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documentation to support subcontract cost. This $16 million was withheld from the subcontractor in the fourth quarter of 2004. We are working with the AMC to resolve this issue.

Withholding of payments. During 2004, the AMC issued a determination that a particular contract clause could cause it to withhold 15% from our invoices until our task orders under the LogCAP contract are definitized. The AMC delayed implementation of this withholding pending further review. The Army Field Support Command (AFSC) has now been delegated authority by the AMC to determine whether or not to implement the withholding. The AFSC has informed us that it will assess the situation on a task order by task order basis and, currently, withholding will continue to be delayed. We do not believe any potential 15% withholding will have a significant or sustained impact on our liquidity because any wit hholding is temporary and ends once the definitization process is complete. During the third quarter of 2004, we and the AMC identified three senior management teams to facilitate negotiation under the LogCAP task orders, and these teams are working to negotiate outstanding issues and definitize task orders as quickly possible. We are continuing to work with our customer to resolve outstanding issues. As of January 18, 2005, 25 task orders for LogCAP totaling over $636 million have been definitized.

In addition, we had unapproved claims totaling $93 million at December 31, 2004, for the LogCAP, RIO, and PCO Oil South contracts. These unapproved claims related to contracts where our costs have exceeded the funded value of the task orders or were related to lost, damaged and destroyed equipment.

We are working diligently with our customers to proceed with significant new work only after we have a fully definitized task order, which should limit withholdings on future task orders.

Cost reporting. We have received notice that a contracting officer for our PCO Oil South project considers our monthly categorization and detail of costs and our ability to schedule and forecast costs to be inadequate, and he has requested corrections be made by March 10, 2005. We expect to be able to make the requested corrections. If we were unable to satisfy our customer, our customer may pursue remedies under the applicable federal acquisition regulations, including terminating the affected contract. Although there can be no assurances, we do not expect that our work on the PCO Oil South project will be so terminated for default. We are in the process of developing an acceptable management cost reporting system, and are supplementing the existing PCO cost reporting team with additional manpower.

Report on estimating system. On December 27, 2004, the DCMA granted continued approval of our estimating system, stating that our estimating system is “acceptable with corrective action.” We are in process of completing these corrective actions. Specifically, based on the unprecedented level of support our employees are providing the military in Iraq, Kuwait, and Afghanistan, we needed to update our estimating policies and procedures to make them better suited to such contingency situations. Additionally, we are in process of developing a detailed training program that will be made available to all estimating personnel to ensure that employees are adequately prepared to deal with the chall enges and unique circumstances associated with a contingency operation.


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Report on purchasing system. As a result of a Contractor Purchasing System Review by the DCMA during the second quarter of 2004, the DCMA granted the continued approval of our government contract purchasing system. The DCMA’s approval letter, dated September 7, 2004, stated that our purchasing system’s policies and practices are “effective and efficient, and provide adequate protection of the Government’s interest.”

The Balkans. We have had inquiries in the past by the DCAA and the civil fraud division of the United States Department of Justice into possible overcharges for work performed during 1996 through 2000 under a contract in the Balkans, which inquiry has not yet been completed by the Department of Justice. Based on an internal investigation, we credited our customer approximately $2 million during 2000 and 2001 related to our work in the Balkans as a result of billings for which support was not readily available. We believe that the preliminary Department of Justice inquiry relates to potential overcharges in connection with a part of the Balkans contract under which approximately $100 million in work was done. We believe that any allegations of overcharges would be without merit.

Note 13. Other Commitments and Contingencies

Nigerian joint venture and investigations

Foreign Corrupt Practices Act investigation. The Securities and Exchange Commission (SEC) is conducting a formal investigation into payments made in connection with the construction and subsequent expansion by TSKJ of a multibillion dollar natural gas liquefaction complex and related facilities at Bonny Island in Rivers State, Nigeria. The United States Department of Justice is also conducting an investigation. TSKJ is a private limited liability company registered in Madeira, Portugal whose members are Technip SA of France, Snamprogetti Netherlands B.V., which is an affiliate of ENI SpA of Italy , JGC Corporation of Japan, and Kellogg Brown & Root, each of which owns 25% of the venture.

The SEC and the Department of Justice have been reviewing these matters in light of the requirements of the United States Foreign Corrupt Practices Act (FCPA). We have produced documents to the SEC both voluntarily and pursuant to subpoenas, and intend to make our employees available to the SEC for testimony. In addition, we understand that the SEC has issued a subpoena to A. Jack Stanley, who most recently served as a consultant and chairman of Kellogg Brown & Root, and to other current and former Kellogg Brown & Root employees. We further understand that the Department of Justice has invoked its authority under a sitting grand jury to obtain letters rogatory for the purpose of obtaining information abroad.


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As of December 31, 2004, we have not accrued any amounts related to this investigation.

If violations of applicable United State antitrust laws occurred, the range of possible penalties includes criminal fines, which could range up to the greater of $10 million in fines per count for a corporation, or twice the gross pecuniary gain or loss and treble civil damages in favor of any persons financially injured by such violations. If such violations occurred, the United States government also would have the discretion to deny future government contracts business to KBR or affiliates or subsidiaries of KBR. Criminal prosecutions under applicable laws of relevant foreign jurisdictions and civil claims by or relationship issues with customers are also possible.

There can be no assurance that the results of these investigations will not have a material adverse effect on our business and results of operations.

As of December 31, 2004, we had not accrued any amounts related to this investigation.

SEC investigation of change in accounting for revenue on long-term construction projects and related disclosures. In August 2004, we reached a settlement in the investigation by the SEC involving our 1998 and 1999 disclosure of and accounting for the recognition of revenue from unapproved claims on long-term construction projects. Our settlement with the SEC covers a failure to disclose a 1998 change in accounting practice. We disclosed the change


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in accounting practice in our 1999 Form 10-K and continued to do so in subsequent periods. The SEC did not determine that we departed from generally accepted accounting principles, nor did it find errors in accounting or fraud. We neither admitted nor denied the SEC’s findings, but paid a $7.5 million civil penalty, and recorded a charge of that amount in the second quarter of 2004. As part of the settlement, the company agreed to cease and desist from committing or causing future securities law violations.

Securities and related litigation. On June 3, 2002, a class action lawsuit was filed against us in federal court on behalf of purchasers of our common stock during the period of approximately May 1998 until approximately May 2002 alleging violations of the federal securities laws in connection with the accounting change and disclosures involved in the SEC investigation discussed above. In addition, the plaintiffs allege that we overstated our revenue from unapproved claims by recognizing amounts not reasonably estimable or probable of collection. After that date, approximately twenty similar class actions were filed against us. Several of those lawsuits also named as defendants Arthur Andersen, LLP, our independent accountants for the period covered by the lawsuits, and several of our present or former officers and directors. The class action cases were later consolidated and the amended consolidated class action complaint, styled Richard Moore, et al. v. Halliburton Company, et al., was filed and served upon us on or about April 11, 2003 (the “Moore class action”). Subsequently, in October 2002 and March 2003, two derivative actions arising out of essentially the same facts and circumstances were filed, one of which was subsequently dismissed, while the other was transferred to the same judge before whom the < FONT style="DISPLAY: inline; FONT-SIZE: 12pt; FONT-FAMILY: Times New Roman, serif">Moore class action was pending.

In early May 2003, we announced that we had entered into a written memorandum of understanding setting forth the terms upon which both the Moore class action and the remaining derivative action would be settled. In June 2003, the lead plaintiffs in the Moore class action filed a motion for leave to file a second amended consolidated complaint, which was granted by the court. In addition to restating the original accounting and disclosure c laims, the second amended consolidated complaint includes claims arising out of the 1998 acquisition of Dresser Industries, Inc. by Halliburton, including that we failed to timely disclose the resulting asbestos liability exposure (the “Dresser claims”). The Dresser claims were included in the settlement discussions leading up to the signing of the memorandum of understanding and are among the claims the parties intended to be resolved by the terms of the proposed settlement of the consolidated Moore class action and the derivative action.

The memorandum of understanding called for Halliburton to pay $6 million, which would be funded by insurance proceeds. After the May 2003 announcement regarding the memorandum of understanding, one of the lead plaintiffs in the consolidated class action announced that it was dissatisfied with the lead plaintiffs’ counsel’s handling of settlement negotiations and what the dissident plaintiff regarded as inadequate communications by the lead plaintiffs’ counsel. The dissident lead plaintiff further asserted that it believes that, for various reasons, the $6 million settlement amount is inadequate.

The attorneys representing the dissident plaintiff filed another class action complaint in August 2003, raising allegations similar to those raised in the second amended consolidated complaint regarding the accounting/disclosure claims and the Dresser claims. In addition, the complaint enhances the Dresser claims to include allegations related to our accounting with respect to the acquisition, integration and reserves of Dresser. We moved to dismiss that complaint, styled Kimble v. Halliburton Company, et al.; however, the court never ruled on our motion and ordered the case consolidated with the Moore class action. On August 3, 2004 the attorneys representing the dissident plaintiff filed a motion for leave to file yet another class action complaint styled Murphey v. Halliburton Company, et al. The court has not ruled on that motion. The proposed complaint raises and augments allegations similar to those in the Moore class action and the Kimble action, including additional allegations regarding disclosure of asbestos liability exposure.


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On June 7, 2004, the court entered an order preliminarily approving the settlement. Following the transfer of the case(s) to another district judge and a final hearing on the fairness of the settlement, on September 9, 2004, the court entered an order holding that evidence of the settlement’s fairness was inadequate and denying the motion for final approval of the settlement in the Moore class action and ordering the parties, among other things, to mediate. After the court’s denial of the motion to approve the settlement, we withdrew from the settlement as we believe we are entitled to do by its terms, although the s ettling plaintiffs assert otherwise. In the days preceding the mediation, two union-sponsored pension funds filed a motion seeking leave to intervene in the consolidated class action litigation. We have opposed that motion. The mediation was held on January 27, 2005 and, at the conclusion of that day, was declared by the mediator to be at an impasse with no settlement having been reached.

After the mediation, the lead plaintiff and lead counsel filed motions to withdraw as lead plaintiff and lead counsel. The court has set a hearing on these motions, which were unopposed, for April 29, 2005. We anticipate that at that time the court will appoint a new lead counsel and issue an order directing which complaint we are required to respond to and the date by which any answer or responsive motion should be filed. We intend to file a motion to dismiss and to vigorously defend the action.

On September 9, 2004, the court ordered that if no objections to the settlement of the derivative action described above were made by October 20, 2004, the court would finally approve the derivative action settlement. On February 18, 2005, the court entered an order dismissing the derivative action with prejudice.

Newmont Gold. In July 1998, Newmont Gold, a gold mining and extraction company, filed a lawsuit over the failure of a blower manufactured and supplied to Newmont by Roots, a former division of Dresser Equipment Group. The plaintiff alleges that during the manufacturing process, Roots had reversed the blades on a component of the blower known as the inlet guide vane assembly, resulting in the blower’s failure and the shutdown of the gold extraction mill for a period of approximately one month during 1996. In January 2002, a Nevada trial court granted summary judgment to Roots on all counts and Newmont appealed. In February 2004, the Nevada Supreme Court reversed the summary judgment and remanded the case to the trial court, holding that fact issues existed which would require trial. Based on pretrial reports, the damages claimed by the plaintiff are in the range of $33 million to $39 million. We believe that we have valid defenses to Newmont’s claims and intend to vigorously defend the matter. As of December 31, 2004, we had not accrued any amounts related to this matter.

Smith International award. In June 2004, a Texas district court jury returned a verdict in our favor in connection with a patent infringement lawsuit we filed against Smith International (Smith). We were awarded $24 million in damages by the jury. We filed the lawsuit in September 2002 seeking damages for Smith’s infringement of our patented Energy Balanced™ roller cone drill bit technology. The jury found that Smith’s competing bits willfully infringed on three of our patents. Under applicable law, the judge has the discretion to enhance the damages to a total amount of up to three times the amount awarded by the jury and to award attorneys’ fees and costs. Subsequent to the ver dict, upon our motion, the court enhanced the jury verdict by $12 million and added another $5 million in attorneys’ fees and costs for a total judgment of $41 million. Post-trial motions for a new trial and for judgment as a matter of law were denied and Smith appealed the judgment.

Related litigation dealing with claims of infringement of the same technology was tried in January and February 2005 in England and a decision is expected shortly. Similar litigation is pending in courts in Italy and is expected to go to trial during 2005.

It is not possible to predict the results of these matters and no amounts have been recorded as of December 31, 2004.

Improper payments reported to the SEC. During the second quarter 2002, we reported to the SEC that one of our foreign subsidiaries operating in Nigeria made improper payments of approximately $2.4 million to entities owned by a Nigerian national who held himself out as a tax consultant, when in fact he was an employee of a local tax authority. The payments were made to obtain favorable tax treatment and clearly violated our Code of Business Conduct and our


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internal control procedures. The payments were discovered during our audit of the foreign subsidiary. We conducted an investigation assisted by outside legal counsel and, based on the findings of the investigation, we terminated several employees. None of our senior officers were involved. We are cooperating with the SEC in its review of the matter. We took further action to ensure that our foreign subsidiary paid all taxes owed in Nigeria. A preliminary assessment of approximately $4 million was issued by the Nigerian tax authorities in the second quarter of 2003. We are cooperating with the Nigerian tax authorities to determine the total amount due as quickly as possible.

Operations in Iran. We received and responded to an inquiry in mid-2001 from the Office of Foreign Assets Control (OFAC) of the United States Treasury Department with respect to operations in Iran by a Halliburton subsidiary that is incorporated in the Cayman Islands. The OFAC inquiry requested information with respect to compliance with the Iranian Transaction Regulations. These regulations prohibit United States citizens, including United States corporations and other United States business organizations, from engaging in commercial, financial, or trade transactions with Iran, unless authorized by OFAC or exempted by statute. Our 2001 written response to OFAC stated that we believed that we were i n compliance with applicable sanction regulations. In January 2004, we received a follow-up letter from OFAC requesting additional information. We responded to this request on March 19, 2004. We understand this matter has now been referred by OFAC to the Department of Justice. In July 2004, we received a grand jury subpoena from an Assistant United States District Attorney requesting the production of documents. We are cooperating with the government’s investigation and have responded to the subpoena by producing documents on September 16, 2004. As of December 31, 2004, we had not accrued any amounts related to this investigation.

Litigation brought by La Nouvelle. In October 2004, La Nouvelle, a subcontractor to us in connection with our government services work in Kuwait and Iraq, filed suit alleging breach of contract and interference with contractual and business relations. The relief sought includes $224 million in damages for breach of contract, which includes $34 million for tortious interference, and an unspecified sum for consequential and punitive damages. The dispute arises from our termination of a master agreement pursuant to which La Nouvelle operated a number of DFACs in Kuwait and Iraq and the replacement of La Nouvelle with ESS which, prior to La Nouvelle’s termination, had served as La Nouvelle’s subcontractor. In addition, La Nouvelle alleges that we wrongfully withheld from La Nouvelle certai n sums due La Nouvelle under its various subcontracts.

While we admit that we have withheld certain sums from La Nouvelle, we believe that we were contractually entitled to do so and that we had the right to terminate the master agreement with La Nouvelle for cause. The case has only recently been filed and our investigation is in its preliminary stages. Accordingly, it is premature to assess the likelihood of an unfavorable result. La Nouvelle has requested and we have agreed to stay all proceedings for a period of 60 days, during which the parties will participate in mediation. We cannot assess the likelihood that mediation will result in a settlement. Should it not, however, it is our intention to vigorously defend the action. As of December 31, 2004, except for amounts previously invoiced to us by La Nouvelle for work performed, we had not accrued any amounts related to this litigation.


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David Hudak and International Hydrocut Technologies Corp. On October 12, 2004, David Hudak and International Hydrocut Technologies Corp. (collectively, Hudak), filed suit against us in the United States District Court alleging civil Racketeer Influenced and Corrupt Organizations Act violations, fraud, breach of contract, unfair trade practices, and other torts. The action, which seeks unspecified damages, arises out of Hudak’s alleged purchase in early 1994 of certain explosive charges that were later alleged by the United States Department of Justice to be military ordnance, the possession of which by persons not possessing the requisite licenses and registrations is unlawful. As a result of t hat allegation by the government, Hudak was charged with, but later acquitted of, certain criminal offenses in connection with his possession of the explosive charges. As mentioned above, the alleged transaction(s) took place more than ten years ago. The fact that most of the individuals that may have been involved, as well as the entities themselves, are no longer affiliated with us, will complicate our investigation. For those reasons and because the litigation is in its most preliminary stages, it is premature to assess the likelihood of an adverse result. It is, however, our intention to vigorously defend this action. As of December 31, 2004, we had not accrued any amounts related to this matter.

Environmental. We are subject to numerous environmental, legal, and regulatory requirements related to our operations worldwide. In the United States, these laws and regulations include, among others:

the Comprehensive Environmental Response, Compensation and Liability Act;

the Resources Conservation and Recovery Act;

the Clean Air Act;

the Federal Water Pollution Control Act; and

the Toxic Substances Control Act.

In addition to the federal laws and regulations, states and other countries where we do business may have numerous environmental, legal, and regulatory requirements by which we must abide. We evaluate and address the environmental impact of our operations by assessing and remediating contaminated properties in order to avoid future liabilities and comply with environmental, legal, and regulatory requirements. On occasion, we are involved in specific environmental litigation and claims, including the remediation of properties we own or have operated as well as efforts to meet or correct compliance-related matters. Our Health, Safety and Environment group has several programs in place to maintain environmental leadership and to prevent the occurrence of environmental contamination.

Letters of credit. In the normal course of business, we have agreements with banks under which approximately $1.1 billion of letters of credit or bank guarantees were outstanding as of December 31, 2004, including $264 million which relate to our joint ventures’ operations. Also included in letters of credit outstanding as of December 31, 2004 and related to the Barracuda-Caratinga project were $277 million of performance letters of credit and $176 million of retainage letters of credit. Certain of the outstanding letters of credit have triggering events which would entitle a bank to require cash collateralization.


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In the fourth quarter of 2003, we entered into a senior secured master letter of credit facility (Master LC Facility) with a syndicate of banks which covered at least 90% of the face amount of our existing letters of credit. The facility expired on December 31, 2004, at which time there were no outstanding advances under the Master LC Facility. Upon the expiration of the Master LC Facility, all letters of credit under the facility ceased to be subject to the terms of the facility and reverted back to the original agreements with the individual banks.

Other commitments. As of December 31, 2004, we had commitments to fund approximately $58 million to certain of our related companies. These commitments arose primarily during the start-up of these entities or due to losses incurred by them. We expect approximately $42 million of the commitments to be paid during the next year.

Liquidated damages. Many of our engineering and construction contracts have milestone due dates that must be met or we may be subject to penalties for liquidated damages if claims are asserted and we were responsible for the delays. These generally relate to specified activities within a project by a set contractual date or achievement of a specified level of output or throughput of a plant we construct. Each contract defines the conditions under which a customer may make a claim for liquidated damages. However, in most instances, liquidated damages are not asserted by the customer but the potential to do so is used in negotiating claims and closing out the contract. We had not accrued liabilities f or $44 million at December 31, 2004 and $243 million at December 31, 2003 of liquidated damages we could incur based upon completing the projects as forecasted. A significant portion of the December 31, 2003 amount was related to the Barracuda-Caratinga project. See Note 3 for further discussion.

Leases. We are obligated under operating leases, principally for the use of land, offices, equipment, field facilities, and warehouses. Total rentals, net of sublease rentals, were as follows:

Millions of dollars		2004			2003			2002
Rental expense		$	693		$	451		$	356

Future total rentals on noncancelable operating leases are as follows: $158 million in 2005; $125 million in 2006; $104 million in 2007; $92 million in 2008; $82 million in 2009; and $453 million thereafter.

Note 14. Income Taxes

The components of the benefit (provision) for income taxes on continuing operations are:

	Years ended December 31
Millions of dollars	2004			2003			2002
Current income taxes:
Federal	$	(88	)	$	(167	)	$	71
Foreign		(156	)		(181	)		(173	)
State		(6	)		1			4
Total current		(250	)		(347	)		(98	)
Deferred income taxes:
Federal		3			80			(11	)
Foreign		6			25			11
State		-			8			18
Total deferred		9			113			18
Provision for income taxes	$	(241	)	$	(234	)	$	(80	)


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The United States and foreign components of income (loss) from continuing operations before income taxes, minority interest, and change in accounting principle are as follows:

	Years ended December 31
Millions of dollars	2004		2003		2002
United States	$	135	$	254	$	(537	)
Foreign		516		358		309
Total	$	651	$	612	$	(228	)

The reconciliations between the actual provision for income taxes on continuing operations and that computed by applying the United States statutory rate to income from continuing operations before income taxes, minority interest, and change in accounting principle are as follows:

	Years ended December 31
	2004			2003			2002
United States statutory rate		35.0	%		35.0	%		35.0	%
State income taxes, net of
federal income tax benefit		0.6			0.9			0.9
Impact of foreign operations		-			0.8			(1.8	)
Adjustments of prior year
taxes		(2.1	)		1.6			14.5
Dispositions		-			(1.6	)		(12.3	)
Valuation allowance		-			-			(71.5	)
Other items, net		3.6			1.5			-
Total effective tax rate on
continuing operations		37.1	%		38.2	%		(35.2	)%

Our impairment loss on Bredero-Shaw during 2002 could not be benefited for tax purposes due to book and tax basis differences in that investment and the limited benefit generated by a capital loss carryback. However, due to changes in circumstances regarding prior years, we are now able to carry back a portion of the capital loss, which resulted in an $11 million benefit in 2003.

The asbestos accruals, the losses on the Bredero-Shaw disposition, and the associated tax benefits net of valuation allowances in continuing operations during 2002 are the primary causes of the unusual 2002 effective tax rate on continuing operations. There were no significant asbestos charges or related tax accruals included in continuing operations for 2004 or 2003.


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The primary components of our deferred tax assets and liabilities and the related valuation allowances, including deferred tax accounts associated with discontinued operations, are as follows:

	December 31
Millions of dollars	2004		2003
Gross deferred tax assets:
Asbestos- and silica-related liabilities	$	1,770	$	1,463
Employee compensation and benefits		263		275
Foreign tax credit carryforward		135		113
Net operating loss carryforwards		115		83
Capitalized research and experimentation		85		100
Construction contract accounting		75		94
Insurance accruals		71		77
Accrued liabilities		69		100
Alternative minimum tax credit carryforward		21		30
Other		260		191
Total	$	2,864	$	2,526
Gross deferred tax liabilities:
Insurance for asbestos- and silica-related
liabilities	$	318	$	631
Depreciation and amortization		182		129
Other		33		11
Total	$	533	$	771
Valuation allowances:
Future tax attributes related to asbestos
and silica litigation	$	1,073	$	624
Foreign tax credit limitation		135		113
Net operating loss carryforwards		43		56
Total	$	1,251	$	793
Net deferred income tax asset	$	1,080	$	962

We have $303 million of net operating loss carryforwards that expire from 2005 through 2014 and net operating loss carryforwards of $71 million with indefinite expiration dates. The federal alternative minimum tax credits are available to reduce future United States federal income taxes on an indefinite basis.

We have established a valuation allowance against foreign tax credit carryovers and certain foreign operating loss carryforwards on the basis that we believe these assets will not be utilized in the statutory carryover period. We also have recorded a valuation allowance on the asbestos and silica liabilities based on the anticipated impact of the future asbestos and silica deductions on our ability to utilize future foreign tax credits. We anticipate that a portion of the asbestos and silica deductions will displace future foreign tax credits, and those credits will expire unutilized.


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Note 15. Shareholders’ Equity and Stock Incentive Plans

The following tables summarize our common stock and other shareholders’ equity activity:

			Capital
			in												Accumulated
			Excess												Other
	Common		of Par			Treasury			Deferred			Retained			Comprehensive
Millions of dollars	Stock		Value			Stock			Compensation			Earnings			Income
Balance at December 31, 2001	$	1,138	$	298		$	(688	)	$	(87	)	$	4,327		$	(236	)
Cash dividends paid		-		-			-			-			(219	)		-
Reissuance of treasury stock for:
Stock purchase, compensation,
and incentive plans, net		1		(24	)		62			-			-			-
Stock issued for acquisition		2		24			-			-			-			-
Treasury stock purchased		-		-			(4	)		-			-			-
Current year awards, net of tax		-		-			-			12			-			-
Tax benefit from exercise of
options		-		(5	)		-			-			-			-
Total dividends and other transactions
with shareholders		3		(5	)		58			12			(219	)		-
Comprehensive income:
Net loss		-		-			-			-			(998	)		-
Other comprehensive income:
Cumulative translation
adjustment		-		-			-			-			-			69
Realization of losses included in
net income		-		-			-			-			-			15
Minimum pension liability
adjustment, net of tax of $70		-		-			-			-			-			(130	)
Unrealized gain on
investments and derivatives		-		-			-			-			-			1
Total comprehensive loss		-		-			-			-			(998	)		(45	)
Balance at December 31, 2002	$	1,141	$	293		$	(630	)	$	(75	)	$	3,110		$	(281	)

Cash dividends paid		-		-			-			-			(219	)		-
Reissuance of treasury stock for:
Stock purchase, compensation, and
incentive plans, net		1		(19	)		60			-			-			-
Treasury stock purchased		-		-			(7	)		-			-			-
Current year awards, net of tax		-		-			-			11			-			-
Tax benefit from exercise of options		-		(1	)		-			-			-			-
Total dividends and other transactions
with shareholders		1		(20	)		53			11			(219	)		-
Comprehensive income:
Net loss		-		-			-			-			(820	)		-
Other comprehensive income:
Cumulative translation
adjustment		-		-			-			-			-			43
Realization of losses included in
net income		-		-			-			-			-			15
Minimum pension liability
adjustment, net of tax of $25		-		-			-			-			-			(88	)
Unrealized gain on
investments and derivatives		-		-			-			-			-			13
Total comprehensive loss		-		-			-			-			(820	)		(17	)
Balance at December 31, 2003	$	1,142	$	273		$	(577	)	$	(64	)	$	2,071		$	(298	)


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			Capital
			in														Accumulated
			Excess			Asbestos											Other
	Common		of Par			Trust		Treasury			Deferred			Retained			Comprehensive
Millions of dollars	Stock		Value			Shares		Stock			Compensation			Earnings			Income
Balance at December 31, 2003	$	1,142	$	273		$	-	$	(577	)	$	(64	)	$	2,071		$	(298	)
Cash dividends paid		-		-			-		-			-			(221	)		-
Reissuance of treasury stock for:
Stock purchase,
compensation, and
incentive plans, net		4		(3	)		-		107			-			-			-
Treasury stock purchased		-		-			-		(7	)		-			-			-
Current year awards, net
of tax		-		-			-		-			(10	)		-			-
Tax benefit from exercise of
options		-		7			-		-			-			-			-
Total dividends and other
transactions with
shareholders		4		4			-		100			(10	)		(221	)		-
Asbestos trust shares		-		-			2,335		-			-			-			-
Comprehensive income:
Net loss		-		-			-		-			-			(979	)		-
Other comprehensive income:
Cumulative translation
adjustment		-		-			-		-			-			-			33
Realization of gains
included in net income		-		-			-		-			-			-			(1	)
Minimum pension liability
adjustment, net of tax
of $49		-		-			-		-			-			-			115
Unrealized gain on
investments and
derivatives, net of tax
of $8		-		-			-		-			-			-			5
Total comprehensive
income (loss)		-		-			-		-			-			(979	)		152
Balance at December 31, 2004	$	1,146	$	277		$	2,335	$	(477	)	$	(74	)	$	871		$	(146	)

*Accumulated other comprehensive income*	December 31
Millions of dollars	2004			2003			2002
Cumulative translation adjustment	$	(31	)	$	(63	)	$	(121	)
Pension liability adjustments		(130	)		(245	)		(157	)
Unrealized gains (losses) on investments and
derivatives		15			10			(3	)
Total accumulated other comprehensive income	$	(146	)	$	(298	)	$	(281	)

*Shares of common stock*	December 31
Millions of shares	2004			2003			2002
Issued		458			457			456
In treasury		(16	)		(18	)		(20	)
Total shares of common stock outstanding		442			439			436

Our 1993 Stock and Incentive Plan provides for the grant of any or all of the following types of awards:

stock options, including incentive stock options and nonqualified stock options;

stock appreciation rights, in tandem with stock options or freestanding;


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restricted stock;

performance share awards; and

stock value equivalent awards.

Under the terms of the 1993 Stock and Incentive Plan, as amended, 49 million shares of common stock have been reserved for issuance to key employees. The plan specifies that no more than 16 million shares can be awarded as restricted stock. At December 31, 2004, 14 million shares were available for future grants under the 1993 Stock and Incentive Plan, of which eight million shares remain available for restricted stock awards.

All stock options under the 1993 Stock and Incentive Plan are granted at the fair market value of the common stock at the grant date. No further stock option grants are being made under the stock plans of acquired companies.

The following table represents our stock options granted, exercised, and forfeited during the past three years, and includes exercised and forfeited shares residual to our acquired companies’ stock plans.

						Weighted
	Number of			Exercise		Average
	Shares			Price per		Exercise Price
Stock Options	(in millions)			Share		per Share
Outstanding at December 31, 2001		17.1		$	8.28 - 61.50	$	35.10
Granted		2.6			9.10 - 19.75		12.57
Exercised		- *			8.93 - 17.21		11.39
Forfeited		(1.2	)		8.28 - 54.50		31.94
Outstanding at December 31, 2002		18.5		$	9.10 - 61.50	$	32.10
Granted		2.4			18.60 - 24.76		23.45
Exercised		(0.4	)		8.28 - 23.52		14.75
Forfeited		(1.0	)		9.10 - 54.50		32.07
Outstanding at December 31, 2003		19.5		$	9.10 - 61.50	$	31.34
Granted		2.2			26.03 - 40.18		29.22
Exercised		(1.5	)		9.10 - 39.55		21.87
Forfeited		(0.8	)		9.10 - 54.50		33.19
Outstanding at December 31, 2004		19.4		$	9.10 - 61.50	$	31.74

*Actual exercises for 2002 were approximately 30,000 shares.

Options outstanding at December 31, 2004 are composed of the following:

	Outstanding
			Weighted				Exercisable
			Average		Weighted				Weighted
	Number of		Remaining		Average		Number of		Average
Range of	Shares		Contractual		Exercise		Shares		Exercise
Exercise Prices	(in millions)		Life		Price		(in millions)		Price
$9.10 - 23.79		4.5		6.6	$	18.54		2.3	$	17.86
$23.80 - 29.87		6.0		5.4		28.39		3.6		28.61
$29.88 - 39.54		5.5		4.9		37.40		4.9		37.90
$39.55 - 61.50		3.4		4.8		45.82		3.3		46.02
$9.10 - 61.50		19.4		5.5	$	31.74		14.1	$	34.15


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There were 13.8 million options exercisable with a weighted average exercise price of $34.59 at December 31, 2003 and 12.5 million options exercisable with a weighted average exercise price of $34.98 at December 31, 2002.

Stock options generally expire 10 years from the grant date. Stock options under the 1993 Stock and Incentive Plan vest ratably over a three- or four-year period. Options under the non-employee directors’ plan vest after six months. Other plans have vesting periods ranging from three to 10 years.

Restricted shares awarded under the 1993 Stock and Incentive Plan were 1,177,312 in 2004, 431,865 in 2003, and 1,706,643 in 2002. The shares awarded are net of forfeitures of 143,908 in 2004, 248,620 in 2003, and 46,894 in 2002. The weighted average fair market value per share at the date of grant of shares granted was $29.80 in 2004, $22.94 in 2003, and $14.95 in 2002.

Our Restricted Stock Plan for Non-Employee Directors allows for each non-employee director to receive an annual award of 400 restricted shares of common stock as a part of compensation. We reserved 100,000 shares of common stock for issuance to non-employee directors. Under this plan we issued 4,000 restricted shares in 2004 and 2003, and 4,400 restricted shares in 2002. At December 31, 2004, 46,000 shares have been issued to non-employee directors under this plan. The weighted average fair market value per share at the date of grant of shares granted was $31.30 in 2004, $22.24 in 2003, and $12.56 in 2002.

Our Employees’ Restricted Stock Plan was established for employees who are not officers, for which 200,000 shares of common stock have been reserved. At December 31, 2004, 151,850 shares (net of 43,550 shares forfeited) have been issued. There were no forfeitures in 2004. Forfeitures were 800 in 2003 and 400 in 2002. No further grants are being made under this plan.

Under the terms of our Career Executive Incentive Stock Plan, 15 million shares of our common stock were reserved for issuance to officers and key employees at a purchase price not to exceed par value of $2.50 per share. At December 31, 2004, 11.7 million shares (net of 2.2 million shares forfeited) have been issued under the plan. The last grant made under this plan was in December 1992. No further grants will be made under the Career Executive Incentive Stock Plan.

Restricted shares issued under the 1993 Stock and Incentive Plan, Restricted Stock Plan for Non-Employee Directors, Employees’ Restricted Stock Plan, and the Career Executive Incentive Stock Plan are limited as to sale or disposition. These restrictions lapse periodically over an extended period of time not exceeding 10 years. Restrictions may also lapse for early retirement and other conditions in accordance with our established policies. Upon termination of employment, shares in which restrictions have not lapsed must be returned to us, resulting in restricted stock forfeitures. The fair market value of the stock on the date of issuance is being amortized and charged to income generally over the average period during which the restrictions lapse, with similar credits to paid-in capital in excess of par valu e. At December 31, 2004, the unamortized amount is $74 million. We recognized compensation costs of $21 million in 2004, $20 million in 2003, and $38 million in 2002.

During 2002, our Board of Directors approved the 2002 Employee Stock Purchase Plan (ESPP) and reserved 12 million shares for issuance. Under the ESPP, eligible employees may have up to 10% of their earnings withheld, subject to some limitations, to be used to purchase shares of our common stock. Unless the Board of Directors shall determine otherwise, each 6-month offering period commences on January 1 and July 1 of each year. The price at which common stock may be purchased under the ESPP is equal to 85% of the lower of the fair market value of the common stock on the commencement date or last trading day of each offering period. Through the ESPP, there were approximately 1.7 million shares sold in 2004, approximately 1.3 million shares sold in 2003, and approximately 541,000 shares sold in 2002.

On April 25, 2000, our Board of Directors approved plans to implement a share repurchase program for up to 44 million shares. No shares were repurchased under this plan in 2004, 2003, or 2002.


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Note 16. Series A Junior Participating Preferred Stock

Our preferred stock consists of five million total authorized shares at December 31, 2004. We previously declared a dividend of one preferred stock purchase right on each outstanding share of common stock. The dividend is also applicable to each share of our common stock that was issued subsequent to adoption of the Rights Agreement entered into with Mellon Investor Services LLC. Each preferred stock purchase right entitles its holder to buy one two-hundredth of a

share of our Series A Junior Participating Preferred Stock, without par value, at an exercise price of $75. These preferred stock purchase rights are subject to antidilution adjustments, which are described in the Rights Agreement entered into with Mellon. The preferred stock purchase rights do not have any voting rights and are not entitled to dividends.

The preferred stock purchase rights become exercisable in limited circumstances involving a potential business combination. After the preferred stock purchase rights become exercisable, each preferred stock purchase right will entitle its holder to an amount of our common stock, or in some circumstances, securities of the acquirer, having a total market value equal to two times the exercise price of the preferred stock purchase right. The preferred stock purchase rights are redeemable at our option at any time before they become exercisable. The preferred stock purchase rights expire on December 15, 2005.

Note 17. Income (Loss) Per Share

Basic income (loss) per share is based on the weighted average number of shares of common stock outstanding during the period. Diluted income (loss) per share includes additional shares of common stock that would have been outstanding if potential common shares (consisting primarily of stock options) with a dilutive effect had been issued. The effect of common stock equivalents on basic weighted average shares outstanding was an additional four million shares in 2004 and three million shares in 2003. Excluded from the computation of diluted income (loss) per share are options to purchase nine million shares of common stock in 2004 and 15 million shares in 2003. These options were outstanding during these years, but were excluded because the option exercise price was greater than the average market price of the sha res of common stock.

On September 30, 2004, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-08, “The Effect of Contingently Convertible Debt on Diluted Earnings per Share,” which changes the treatment of contingently convertible debt instruments in the calculation of diluted earnings per share. Contingently convertible debt instruments are financial instruments that include a contingent feature, such as the debt becoming convertible into shares of common stock of the issuer if the issuer’s common stock price has exceeded a predetermined threshold for a specified time period. Our 3.125% convertible senior notes due 2023 are an example of these types of instruments. Prior to the effective date of the new consensus, we excluded the potential dilutive effect of the conversion feature from diluted e arnings per share until the contingency threshold was met (it has never been met in the case of the 3.125% convertible senior notes). EITF Issue No. 04-08 provides that these debt instruments should be included in the earnings per share computation, if dilutive, regardless of whether the contingent feature has been met.

As a result of the new EITF, in December 2004 we entered into a supplemental indenture that requires us to satisfy our conversion obligation for our $1.2 billion 3.125% convertible senior notes in cash, rather than in common stock, for at least the aggregate principal amount of the notes, thus reducing the resulting potential earnings dilution to only include the conversion premium, which is the difference between the conversion price per share of common stock and the average share price. The conversion price of $37.65 per share of common stock was greater than our average share price in each of the quarters since issuance of the notes in June 2003 and, as a result, did not result in dilution.

For 2002, we used the basic weighted average shares in the calculation of diluted loss per share as the effect of the common stock equivalents, which totaled two million shares for this period, would have been antidilutive based upon the loss from continuing operations.


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Note 18. Financial Instruments and Risk Management

Foreign exchange risk. Techniques in managing foreign exchange risk include, but are not limited to, foreign currency borrowing and investing and the use of currency derivative instruments. We selectively manage significant exposures to potential foreign exchange losses considering current market conditions, future operating activities, and

the associated cost in relation to the perceived risk of loss. The purpose of our foreign currency risk management activities is to protect us from the risk that the eventual dollar cash flows resulting from the sale and purchase of products and services in foreign currencies will be adversely affected by changes in exchange rates.

We manage our currency exposure through the use of currency derivative instruments as it relates to the major currencies, which are generally the currencies of the countries in which we do the majority of our international business. These contracts generally have an expiration date of two years or less. Forward exchange contracts, which are commitments to buy or sell a specified amount of a foreign currency at a specified price and time, are generally used to manage identifiable foreign currency commitments. Forward exchange contracts and foreign exchange option contracts, which convey the right, but not the obligation, to sell or buy a specified amount of foreign currency at a specified price, are generally used to manage exposures related to assets and liabilities denominated in a foreign currency. None of the f orward or option contracts are exchange traded. While derivative instruments are subject to fluctuations in value, the fluctuations are generally offset by the value of the underlying exposures being managed. The use of some contracts may limit our ability to benefit from favorable fluctuations in foreign exchange rates.

Foreign currency contracts are not utilized to manage exposures in some currencies due primarily to the lack of available markets or cost considerations (non-traded currencies). We attempt to manage our working capital position to minimize foreign currency commitments in non-traded currencies and recognize that pricing for the services and products offered in these countries should cover the cost of exchange rate devaluations. We have historically incurred transaction losses in non-traded currencies.

Assets, liabilities, and forecasted cash flows denominated in foreign currencies. We utilize the derivative instruments described above to manage the foreign currency exposures related to specific assets and liabilities, which are denominated in foreign currencies; however, we have not elected to account for these instruments as hedges for accounting purposes. Additionally, we utilize the derivative instruments described above to manage forecasted cash flows denominated in foreign currencies generally related to long-term engineering and construction projects. Beginning in 2003, we designated these contracts related to engineering and construction projects as cash flow hedges. The ineffective portion of these hedges was included in operating income in the accompanying consolidated statement of operations and was not material in 2004 or 2003. The unrealized net gains on these cash flow hedges were approximately $23 million as of December 31, 2004 and $10 million as of December 31, 2003 and are included in other comprehensive income in the accompanying consolidated balance sheet. We expect approximately $23 million of the unrealized net gain on these cash flow hedges to be reclassified into earnings within a year, as most of these cash flow hedges settle in the next 12 months. Changes in the timing or amount of the future cash flows being hedged could result in hedges becoming ineffective and, as a result, the amount of unrealized gain or loss associated with those hedges would be reclassified from other comprehensive income into earnings. At December 31, 2004, the maximum length of time over which we are hedging our exposure to the variability in future cash flows associated with foreign currency forecasted transactions is 16 months. In 2002, we did not designate these derivative contracts related to engineering and construction projects as cash flow hedges. The fair value of these contracts was $27 million as of December 31, 2004, and immaterial as of December 31, 2003 and 2002.

Notional amounts and fair market values. The notional amounts of open forward contracts and option contracts were $1.4 billion at December 31, 2004 and $1.0 billion at December 31, 2003. The notional amounts of our foreign exchange contracts do not generally represent amounts exchanged by the parties, and thus, are not a measure of our


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exposure or of the cash requirements relating to these contracts. The amounts exchanged are calculated by reference to the notional amounts and by other terms of the derivatives, such as exchange rates.

Credit risk. Financial instruments that potentially subject us to concentrations of credit risk are primarily cash equivalents, investments, and trade receivables. It is our practice to place our cash equivalents and investments in high quality securities with various investment institutions. We derive the majority of our revenue from our United States government contracts, primarily for projects in the Middle East, and from sales and services, including engineering and construction, to the energy industry. Within the energy industry, trade receivables are generated from a broad and diverse group of customers. There are concentrations of receivables in the United States and the United Kingdom. We ma intain an allowance for losses based upon the expected collectibility of all trade accounts receivable. In addition, see Note 6 for discussion of United States government receivables.

There are no significant concentrations of credit risk with any individual counterparty related to our derivative contracts. We select counterparties based on their profitability, balance sheet, and a capacity for timely payment of financial commitments, which is unlikely to be adversely affected by foreseeable events.

Interest rate risk. We have several debt instruments outstanding which have both fixed and variable interest rates. We manage our ratio of fixed- to variable-rate debt through the use of different types of debt instruments and derivative instruments. As of December 31, 2004, we held no interest rate derivative instruments.

Fair market value of financial instruments. The estimated fair market value of long-term debt was $3.7 billion at December 31, 2004 and $3.6 billion at December 31, 2003, as compared to the carrying amount of $3.9 billion at December 31, 2004 and $3.4 billion at December 31, 2003. The fair market value of fixed-rate long-term debt is based on quoted market prices for those or similar instruments. The carrying amount of variable-rate long-term debt approximates fair market value because these instruments reflect market changes to interest rates. The carrying amount of short-term financial instruments, cash and equivalents, receivables, short-term notes payable, and accounts payable, as reflected in the consolidated b alance sheets, approximates fair market value due to the short maturities of these instruments. The currency derivative instruments are carried on the balance sheet at fair value and are based upon third-party quotes.

Note 19. Retirement Plans

Our company and subsidiaries have various plans which cover a significant number of our employees. These plans include defined contribution plans, defined benefit plans, and other postretirement plans.

our defined contribution plans provide retirement contributions in return for services rendered. These plans provide an individual account for each participant and have terms that specify how contributions to the participant’s account are to be determined rather than the amount of pension benefits the participant is to receive. Contributions to these plans are based on pretax income and/or discretionary amounts determined on an annual basis. Our expense for the defined contribution plans for both continuing and discontinued operations totaled $147 million, $87 million, and $80 million in 2004, 2003, and 2002, respectively. For 2004, we amended certain defined contribution plans to allow for a non-elective contribution, which resulted in an increase of $53 million over the 2003 expense;

our defined benefit plans include both funded and unfunded pension plans, which define an amount of pension benefit to be provided, usually as a function of age, years of service, or compensation; and


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- our postretirement medical plans are offered to specific eligible employees. These plans are contributory.

For some plans, our liability is limited to a fixed contribution amount for each participant or dependent.

The plan participants share the total cost for all benefits provided above our fixed contribution.

Participants' contributions are adjusted as required to cover benefit payments. We have made no commitment to adjust the amount of our contributions; therefore, the computed accumulated postretirement benefit obligation amount is not affected by the expected future health care cost inflation rate.

Dresser Retiree Medical. Through 2003, we were responsible for the majority of the costs for the Dresser Retiree Medical Plan. An amendment was made to this plan at the end of 2003 to limit our share of the costs and eventually eliminate certain plans in 2005. We presented the impact of this amendment in our 2003 notes to consolidated financial statements which reduced our projected benefit obligation by $86 million and increased our unrecognized prior service benefit by the same amount, with no impact to our balance sheet or statement of operations. In December 2004, the United States District Court ruled that we must continue to maintain the Dresser Retiree Medical Plan as we had in the past. We h ave revised our prior year presentation of the projected benefit obligation and unrecognized prior service benefit to reflect the plan at its pre-amendment amounts. We also adjusted our annual postretirement benefit expense by $13 million in the fourth quarter of 2004.

Plan assets, expenses, and obligation for retirement plans in the following tables include both continuing and discontinued operations. We use a September 30 measurement date for our international plans and an October 31 measurement date for our domestic plans.

	Pension Benefits												Other
	United						United						Postretirement
*Benefit obligations*	States			Int’l			States			Int’l			Benefits
Millions of dollars	2004						2003						2004			2003
Change in benefit obligation
Benefit obligation at beginning of period	$	160		$	2,501		$	144		$	2,239		$	188		$	186
Service cost		1			92			1			72			1			1
Interest cost		10			155			10			120			11			12
Plan participants’ contributions		-			22			-			17			12			13
Effect of business combinations and new plans		-			14			-			12			-			-
Amendments		-			(1	)		-			-			-			(7	)
Divestitures		-			-			-			(56	)		-			-
Settlements/curtailments		-			(9	)		-			4			-			-
Currency fluctuations		-			371			-			54			-			-
Actuarial gain/(loss)		8			72			18			107			(16	)		9
Benefits paid		(13	)		(90	)		(13	)		(68	)		(21	)		(26	)
Benefit obligation at end of period	$	166		$	3,127		$	160		$	2,501		$	175		$	188
Accumulated benefit obligation at end
of period	$	165		$	2,451		$	158		$	2,230		$	-		$	-

	Pension Benefits												Other
	United						United						Postretirement
*Plan assets*	States			Int’l			States			Int’l			Benefits
Millions of dollars	2004						2003						2004			2003
Change in plan assets
Fair value of plan assets at beginning of period	$	113		$	2,003		$	113		$	1,886		$	-		$	-
Actual return on plan assets		17			259			8			152			-			-
Employer contributions		8			77			2			53			9			13
Settlements and transfers		-			(8	)		-			(33	)		-			-
Plan participants’ contributions		-			22			3			17			12			13
Effect of business combinations and new plans		-			9			-			-			-			-
Divestitures		-			-			-			(47	)		-			-
Currency fluctuations		-			304			-			43			-			-
Benefits paid		(13	)		(90	)		(13	)		(68	)		(21	)		(26	)
Fair value of plan assets at end of period	$	125		$	2,576		$	113		$	2,003		$	-		$	-


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Our pension plan weighted-average asset allocations at December 31, 2004 and 2003 and the target allocations for 2005 by asset category are as follows:

				Percentage of Plan Assets at Year-end
	Target			United						United
	Allocation			States			Int’l			States			Int’l
	2005			2004						2003
Asset category
Equity securities		55%-70	%		63	%		64	%		45	%		63	%
Debt securities		30%-35	%		33	%		34	%		23	%		34	%
Real estate		0	%		0	%		0	%		0	%		0	%
Other - STIF		0%-5	%		4	%		2	%		32	%		3	%
Total		100	%		100	%		100	%		100	%		100	%

Our investment strategy varies by country depending on the circumstances of the underlying plan. Typically, less mature plan benefit obligations are funded by using more equity securities, as they are expected to achieve long-term growth while exceeding inflation. More mature plan benefit obligations are funded using more fixed income securities, as they are expected to produce current income with limited volatility. Risk management practices include the use of multiple asset classes and investment managers within each asset class for diversification purposes. Specific guidelines for each asset class and investment manager are implemented and monitored.

Funded status

The funded status of the plans, reconciled to the amount reported on the consolidated balance sheets, is as follows:

	Pension Benefits												Other
	United						United						Postretirement
	States			Int’l			States			Int’l			Benefits
End of year in millions of dollars	2004						2003						2004			2003
Fair value of plan assets at end of period	$	125		$	2,576		$	113		$	2,003		$	-		$	-
Benefit obligation at end of period		166			3,127			160			2,501			175			188

Funded status	$	(41	)	$	(551	)	$	(47	)	$	(498	)	$	(175	)	$	(188	)
Employer contribution		-			19			-			5			1			2
Unrecognized transition asset		(1	)		-			(1	)		(1	)		-			-
Unrecognized actuarial loss		74			632			76			594			12			28
Unrecognized prior service cost (benefit)		-			(3	)		1			(1	)		(4	)		(4	)
Purchase accounting adjustment		-			(82	)		-			(77	)		-			-
Net amount recognized	$	32		$	15		$	29		$	22		$	(166	)	$	(162	)

Amounts recognized in the consolidated balance sheets are as follows:

	Pension Benefits												Other
	United						United						Postretirement
	States			Int’l			States			Int’l			Benefits
End of year in millions of dollars	2004						2003						2004			2003
Amounts recognized in the consolidated
balance sheets
Prepaid benefit cost	$	34		$	103		$	31		$	95		$	-		$	-
Accrued benefit liability including additional
minimum liability		(74	)		(214	)		(76	)		(361	)		(166	)		(162	)
Intangible asset		-			8			-			8			-			-
Accumulated other comprehensive income,
net of tax		47			83			48			197			-			-
Deferred tax asset		25			35			26			83			-			-
Net amount recognized	$	32		$	15		$	29		$	22		$	(166	)	$	(162	)


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We reduced our additional minimum pension liability for the underfunded defined benefit plans of $164 million in 2004, of which $115 million was recorded as “Other comprehensive income.” We recognized an additional minimum pension liability of $107 million in 2003, of which $88 million was recorded as “Other comprehensive income.” The additional minimum liability is equal to the excess of the accumulated benefit obligation over plan assets and accrued liabilities. A corresponding amount is recognized as either an intangible asset or a reduction of shareholders’ equity.

The projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets as of December 31, 2004 and 2003 are as follows:

	Pension Benefits
Millions of dollars	2004		2003
Projected benefit obligation	$	1,942	$	2,630
Accumulated benefit obligation	$	1,629	$	2,363
Fair value of plan assets	$	1,503	$	2,087

Expected cash flows

Contributions. Funding requirements for each plan are determined based on the local laws of the country where such plan resides. In certain countries the funding requirements are mandatory while in other countries they are discretionary. We currently expect to contribute $72 million to our international pension plans in 2005. For our domestic plans, we expect our contributions to be in the range of $1 million to $5 million in 2005. We do not have a required minimum contribution for our domestic plans; however, we may make additional discretionary contributions, which will be determined after the actuarial valuations are complete.

Benefits

	Pension Benefits				Other
	United				Postretirement
Millions of dollars	States		Int’l		Benefits
2005	$	12	$	96	$	17
2006		13		90		16
2007		12		93		16
2008		10		99		16
2009		11		101		16
Years 2010-2014	$	54	$	573	$	77

Net periodic cost

	Pension Benefits																		Other
	United						United						United						Postretirement
End of year in	States			Int’l			States			Int’l			States			Int’l			Benefits
millions of dollars	2004						2003						2002						2004			2003		2002
Components of net
periodic benefit
cost
Service cost	$	1		$	92		$	1		$	72		$	1		$	72		$	1		$	1	$	1
Interest cost		10			155			10			120			9			102			11			12		11
Expected return on																				-
plan assets		(11	)		(173	)		(12	)		(136	)		(13	)		(106	)		-			-		-
Transition amount		-			(1	)		-			(1	)		-			(2	)		-			-		-
Amortization of prior
service cost		-			-			-			-			(2	)		(6	)		(1	)		-		-
Settlements/curtailments		1			(2	)		2			-			-			(2	)		-			-		-
Recognized actuarial																				-
(gain) loss		3			16			1			18			1			3			1			1		(1	)
Net periodic benefit
(income) cost	$	4		$	87		$	2		$	73		$	(4	)	$	61		$	12		$	14	$	11


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Assumptions

Assumed long-term rates of return on plan assets, discount rates for estimating benefit obligations, and rates of compensation increases vary for the different plans according to the local economic conditions. The rates used are as follows:

Weighted-average
assumptions used to	Pension Benefits																		Other
determine benefit	United						United						United						Postretirement
obligations at	States			Int’l			States			Int’l			States			Int’l			Benefits
measurement date	2004						2003						2002						2004			2003			2002
Discount rate		5.75	%		2.5-8.0	%		6.25	%		2.5-9.0	%		7.0	%		5.25-7.5	%		5.75	%		6.25	%		7.0	%
Rate of compensation
increase		4.5	%		2.0-5.0	%		4.5	%		2.0-6.5	%		4.5	%		3.0-7.0	%		N/A			N/A			N/A

Weighted-average
assumptions used to
determine net	Pension Benefits																		Other
periodic benefit cost	United						United						United						Postretirement
for years ended	States			Int’l			States			Int’l			States			Int’l			Benefits
December 31	2004						2003						2002						2004			2003			2002
Discount rate		6.25	%		2.5-9.0	%		7.0	%		2.5-7.5	%		7.25	%		5.0-8.0	%		6.25	%		7.0	%		7.25	%
Expected return on
plan assets		8.5	%		5.25-7.5	%		8.75	%		5.5-8.0	%		9.0	%		5.5-9.0	%		N/A			N/A			N/A
Rate of compensation
increase		4.5	%		2.0-6.5	%		4.5	%		2.0-7.0	%		4.5	%		3.0-7.0	%		N/A			N/A			N/A

The weighted average assumptions for the Nigerian and Indonesian plans are not included in the above table as the plans are immaterial.

The overall expected long-term rate of return on assets is determined based upon an evaluation of our plan assets, historical trends, and experience taking into account current and expected market conditions.

Assumed health care cost trend
rates at December 31	2004			2003			2002
Health care cost trend rate
assumed for next year		11.5	%		13.0	%		13.0	%
Rate to which the cost trend
rate is assumed to decline
(the ultimate trend rate)		5.0	%		5.0	%		5.0	%
Year that the rate reached the
ultimate trend rate		2008			2008			2007

Assumed health care cost trend rates are not expected to have a significant impact on the amounts reported for the total of the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	One-Percentage-Point
Millions of dollars	Increase		(Decrease)
Effect on total of service and
interest cost components	$	1	$	-
Effect on the postretirement
benefit obligation	$	9	$	(8	)


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Note 20. Related Companies

We conduct some of our operations through joint ventures which are in partnership, corporate, and other business forms and are principally accounted for using the equity method. Financial information pertaining to related companies for our continuing operations is set out in the following tables. This information includes the total related-company balances and not our proportional interest in those balances.

Our larger unconsolidated entities include Subsea 7, Inc., a 50%-owned subsidiary, formed in May 2002, whose results are reported in our Production Optimization segment, and the partnerships created to construct the Alice Springs to Darwin rail line in Australia, whose results are reported in our Government and Infrastructure segment. In January 2005, we completed the sale of Subsea 7, Inc. to our joint venture partner, Siem Offshore.

Combined summarized financial information for all jointly owned operations that are accounted for under the equity method is as follows:

Combined Operating Results	Years ended December 31
Millions of dollars	2004			2003		2002
Revenue	$	3,388		$	4,438	$	4,045
Operating income	$	(34	)	$	263	$	450
Net income	$	(58	)	$	230	$	409

Combined Financial Position	December 31
Millions of dollars	2004		2003
Current assets	$	2,390	$	2,542
Noncurrent assets		3,226		3,054
Total	$	5,616	$	5,596
Current liabilities	$	2,049	$	2,361
Noncurrent liabilities		2,832		2,277
Minority interests		-		3
Shareholders’ equity		735		955
Total	$	5,616	$	5,596

The FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (FIN 46), in January 2003. In December 2003, the FASB issued FIN 46R, a revision which supersedes the original interpretation. We adopted FIN 46R effective January 1, 2004.

FIN 46R requires the consolidation of entities in which a company absorbs a majority of another entity’s expected losses, receives a majority of the other entity’s expected residual returns, or both, as a result of ownership, contractual, or other financial interests in the other entity. Previously, entities were generally consolidated based upon a controlling financial interest through ownership of a majority voting interest in the entity.

We have identified the following variable interest entities:

during the second quarter of 2001, we formed a joint venture, WellDynamics, with Shell in which we held a 50% equity interest and accounted for the investment using the equity method in our Digital and Consulting Solutions segment. The joint venture was established for the further development and deployment of new technologies related to completions and well intervention products and services. In the first quarter of 2004, Halliburton and Shell restructured WellDynamics whereby Halliburton acquired an additional 1% of WellDynamics from Shell, giving Halliburton 51% ownership and control of day-to-day operations. The


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joint venture is considered a variable interest entity under FIN 46, and we have determined that we are the primary beneficiary of the entity. Beginning in the first quarter of 2004, WellDynamics was consolidated and included in our Production Optimization segment. The consolidation of WellDynamics resulted in an increase to our goodwill of $109 million, which was previously carried as equity method goodwill in our investment balance, and an increase in long-term debt of $27 million. There are no assets of WellDynamics that collateralize its obligations;

during 2001, we formed a joint venture which owns and operates heavy equipment transport vehicles in the United Kingdom in which we own a 50% equity interest with two unrelated partners, each owning a 25% equity interest. This variable interest entity was formed to construct, operate, and service certain assets for a third party, and was funded with third-party debt. The construction of the assets was completed in the second quarter of 2004, and the operating and service contract related to the assets extends through 2023. The proceeds from the debt financing were used to construct the assets and will be paid down with cash flows generated during the operation and service phase of the contract with the third party. As of December 31, 2004, the joint venture had total assets of $174 million and total liabilities of $175 million. Our aggregate exposure to loss as a result of our involvement with this joint ventur e is limited to our equity investment and subordinated debt of $12 million and any future losses related to the operation of the assets. We are not the primary beneficiary. The joint venture is accounted for under the equity method of accounting in our Government and Infrastructure segment; and

we are involved in three privately funded initiatives executed through joint ventures to design, build, operate, and maintain roadways for certain government agencies in the United Kingdom. We have a 25% ownership interest in these joint ventures and account for them under the equity method. These joint ventures are considered variable interest entities as they were initially formed with little equity contributed by the partners. The joint ventures have obtained financing through third parties that is not guaranteed by us. We are not the primary beneficiary of these joint ventures and will, therefore, continue to account for them using the equity method. As of December 31, 2004, these joint ventures had total assets of $1.5 billion and total liabilities of $1.4 billion. Our maximum exposure to loss is limited to our equity investments in and loans to the joint ventures, which totaled $42 million at December 31, 2004, and our share of any future losses to the construction of these roadways.

Note 21. Reorganization of Business Operations

Effective October 1, 2004, we restructured KBR into two segments, Government and Infrastructure and Energy and Chemicals. In 2004, we recorded restructuring and related costs of $40 million related to the reorganization. The total restructuring charges consist of $31 million in personnel termination benefits and $9 million in impairment charges on technology-related assets. For the year ended December 31, 2004, $32 million of the restructuring charge was included in “Cost of services” and $8 million was included in “General and administrative” on the consolidated statements of operations. As of December 31, 2004, $19 million had not been paid and is included in “Other current liabilities.”

Now that we have resolved our asbestos and silica liability and our affected subsidiaries have exited Chapter 11 reorganization proceedings, we intend to separate KBR from Halliburton, which could include a transaction involving a spin-off, split-off, public offering, or sale of KBR or its operations. In order to maximize KBR’s value for our shareholders, and to determine the most appropriate form of the transaction and its components, it may be necessary for KBR to establish a track record of positive earnings for a number of quarters and to seek resolution of governmental issues, investigations, and other disputes.


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On March 18, 2002, we announced plans to restructure our businesses into two operating subsidiary groups, the Energy Services Group and KBR. As part of this reorganization, we separated and consolidated the entities in our Energy Services Group together as direct and indirect subsidiaries of Halliburton Energy Services, Inc. We also separated and consolidated the entities in KBR together as direct and indirect subsidiaries of the former Dresser Industries, Inc., which became a limited liability company during the second quarter of 2002 and was renamed DII Industries, LLC. The reorganization of subsidiaries facilitated the separation of our business groups, organizationally and financially, which we believe will significantly improve operating efficiencies in both, while streamlining management and easing manpower requirements. In addition, many support functions, which were previously shared, were moved into the two business groups. As a result, we took actions during 2002 to reduce our cost structure by reducing personnel, moving previously shared support functions into the two business groups, and realigning ownership of international subsidiaries by group.

In 2002, we incurred costs related to the restructuring of approximately $107 million which consisted of the following:

$64 million in personnel-related expense;

$17 million of asset-related write-downs;

$20 million in professional fees related to the restructuring; and

$6 million related to contract terminations.

As of December 31, 2004, all amounts related to the 2002 restructuring have been paid and the balance in the restructuring reserve account has be reduced to zero.


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HALLIBURTON COMPANY

Selected Financial Data

(Unaudited)

Millions of dollars and shares	Years ended December 31
except per share and employee data	2004			2003			2002			2001			2000
Total revenue	$	20,466		$	16,271		$	12,572		$	13,046		$	11,944
Total operating income (loss)		837			720			(112	)		1,084			462
Nonoperating expense, net		(186	)		(108	)		(116	)		(130	)		(127	)
Income (loss) from continuing
operations before income taxes
and minority interest		651			612			(228	)		954			335
Provision for income taxes		(241	)		(234	)		(80	)		(384	)		(129	)
Minority interest in net income of
consolidated subsidiaries		(25	)		(39	)		(38	)		(19	)		(18	)
Income (loss) from continuing
operations	$	385		$	339		$	(346	)	$	551		$	188
Income (loss) from discontinued
operations	$	(1,364	)	$	(1,151	)	$	(652	)	$	257		$	313
Net income (loss)	$	(979	)	$	(820	)	$	(998	)	$	809		$	501
Basic income (loss) per share
Continuing operations	$	0.88		$	0.78		$	(0.80	)	$	1.29		$	0.42
Net income (loss)		(2.25	)		(1.89	)		(2.31	)		1.89			1.13
Diluted income (loss) per share)
Continuing operations		0.87			0.78			(0.80	)		1.28			0.42
Net income (loss)		(2.22	)		(1.88	)		(2.31	)		1.88			1.12
Cash dividends per share		0.50			0.50			0.50			0.50			0.50
Return on average shareholders’
equity		(30.22	)%		(26.86	)%		(24.02	)%		18.64	%		12.20	%
Financial position
Net working capital	$	2,898		$	1,355		$	2,288		$	2,665		$	1,742
Total assets		15,796			15,499			12,844			10,966			10,192
Property, plant, and equipment, net		2,553			2,526			2,629			2,669			2,410
Long-term debt (including current
maturities)		3,940			3,437			1,476			1,484			1,057
Shareholders’ equity		3,932			2,547			3,558			4,752			3,928
Total capitalization		7,887			6,002			5,083			6,280			6,555
Shareholders’ equity per share		8.90			5.80			8.16			10.95			9.20
Average common shares
outstanding (basic)		437			434			432			428			442
Average common shares
outstanding (diluted)		441			437			432			430			446
Other financial data
Capital expenditures	$	(575	)	$	(515	)	$	(764	)	$	(797	)	$	(578	)
Long-term borrowings
(repayments), net		476			1,896			(15	)		412			(308	)
Depreciation, depletion and
amortization expense		509			518			505			531			503
Goodwill amortization included
in depreciation, depletion
and amortization expense		-			-			-			42			44
Payroll and employee benefits		(5,608	)		(5,154	)		(4,875	)		(4,818	)		(5,260	)
Number of employees		97,000			101,000			83,000			85,000			93,000


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HALLIBURTON COMPANY

Quarterly Data and Market Price Information

(Unaudited)

	Quarter
Millions of dollars except per share data	First			Second			Third			Fourth			Year
2004
Revenue	$	5,519		$	4,956		$	4,790		$	5,201		$	20,466
Operating income (loss)		175			(26	)		342			346			837
Income (loss) from continuing operations		76			(58	)		186			181			385
Loss from discontinued operations		(141	)		(609	)		(230	)		(384	)		(1,364	)
Net loss		(65	)		(667	)		(44	)		(203	)		(979	)
Earnings per share:
Basic income (loss) per share:
Income (loss) from continuing operations		0.17			(0.13	)		0.43			0.41			0.88
Loss from discontinued operations		(0.32	)		(1.39	)		(0.54	)		(0.88	)		(3.13	)
Net loss		(0.15	)		(1.52	)		(0.11	)		(0.47	)		(2.25	)
Diluted income (loss) per share:
Income (loss) from continuing operations		0.17			(0.13	)		0.42			0.40			0.87
Loss from discontinued operations		(0.32	)		(1.39	)		(0.51	)		(0.86	)		(3.09	)
Net loss		(0.15	)		(1.52	)		(0.09	)		(0.46	)		(2.22	)
Cash dividends paid per share		0.125			0.125			0.125			0.125			0.50
Common stock prices (1)
High		32.70			32.35			33.98			41.69			41.69
Low		25.80			27.35			26.45			33.08			25.80
2003
Revenue	$	3,060		$	3,599		$	4,148		$	5,464		$	16,271
Operating income		142			71			204			303			720
Income from continuing operations		59			42			92			146			339
Loss from discontinued operations		(8	)		(16	)		(34	)		(1,093	)		(1,151	)
Cumulative effect of change in accounting
principal, net of tax benefit of $5		(8	)		-			-			-			(8	)
Net income (loss)		43			26			58			(947	)		(820	)
Earnings per share:
Basic income (loss) per share:
Income from continuing operations		0.14			0.09			0.21			0.34			0.78
Loss from discontinued operations		(0.02	)		(0.03	)		(0.08	)		(2.52	)		(2.65	)
Cumulative effect of change in accounting
principal, net of tax benefit		(0.02	)		-			-			-			(0.02	)
Net income (loss)		0.10			0.06			0.13			(2.18	)		(1.89	)
Diluted income (loss) per share:
Income from continuing operations		0.14			0.09			0.21			0.34			0.78
Loss from discontinued operations		(0.02	)		(0.03	)		(0.08	)		(2.51	)		(2.64	)
Cumulative effect of change in accounting
principal, net of tax benefit		(0.02	)		-			-			-			(0.02	)
Net income (loss)		0.10			0.06			0.13			(2.17	)		(1.88	)
Cash dividends paid per share		0.125			0.125			0.125			0.125			0.50
Common stock prices (1)
High		21.79			24.97			25.90			27.20			27.20
Low		17.20			19.98			20.50			22.80			17.20

(1) New York Stock Exchange - composite transactions high and low intraday price.


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PART III

Item 10. Directors and Executive Officers of Registrant.

The information required for the directors of the Registrant is incorporated by reference to the Halliburton Company Proxy Statement for our 2005 Annual Meeting of Stockholders (File No. 1-3492), under the caption “Election of Directors.” The information required for the executive officers of the Registrant is included under Part I on pages 11 and 12 of this annual report.

Audit Committee Financial Expert

In the business judgment of the Board of Directors, all five members of the Audit Committee, Robert L. Crandall, Kenneth T. Derr, W. R. Howell, J. Landis Martin, and C. J. Silas, are independent and have accounting or related financial management experience required under the listing standards and have been designated by the Board of Directors as “audit committee financial experts.”

Item 11. Executive Compensation.

This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2005 Annual Meeting of Shareholders (File No. 1-3492) under the captions “Compensation Committee Report on Executive Compensation,” “Comparison of Cumulative Total Return,” “Summary Compensation Table,” “Option Grants for Fiscal 2004,” “Aggregated Option Exercises in Fiscal 2004 and December 31, 2004 Option Values,” “Long-term Incentive Plans - Awards in Fiscal 2004,” “Employment Contracts and Change-in-Control Arrangements,” and “Directors’ Compensation.”

Item 12(a). Security Ownership of Certain Beneficial Owners.

This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2005 Annual Meeting of Stockholders (File No. 1-3492) under the caption “Stock Ownership of Certain Beneficial Owners and Management.”

Item 12(b). Security Ownership of Management.

Item 12(c). Changes in Control.

Not applicable.

Item 12(d). Securities Authorized for Issuance Under Equity Compensation Plans.

This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2005 Annual Meeting of Stockholders (File No. 1-3492) under the caption “Equity Compensation Plan Information.”

Item 13. Certain Relationships and Related Transactions.

This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2005 Annual Meeting of Stockholders (File No. 1-3492) under the caption “Certain Relationships and Related Transactions” to the extent any disclosure is required.

Item 14. Principal Accountant Fees and Services.

This information is incorporated by reference to the Halliburton Company Proxy Statement for our 2005 Annual Meeting of Stockholders (File No. 1-3492) under the caption “Fees Paid to KPMG LLP.”


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PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a) 1. Financial Statements:

The reports of the Independent Registered Public Accounting Firm and the financial statements of the

Company as required by Part II, Item 8, are included on pages 63 and 64 and pages 65 through 119 of

this annual report. See index on page 14.

2. Financial Statement Schedules: Page No.

Report on supplemental schedule of KPMG LLP 133

Schedule II - Valuation and qualifying accounts for the three years ended

December 31, 2004 134

Note: All schedules not filed with this report required by Regulation S-X have been omitted as not

applicable or not required or the information required has been included in the notes to financial

statements.

3. Exhibits:

Exhibit

Number Exhibits

2.1 Disclosure Statement for the Proposed Joint Pre-packaged Plan of Reorganization for Mid-Valley, Inc., DII Industries, LLC, Kellogg Brown & Root, Inc., KBR Technical Services, Inc., Kellogg Brown & Root Engineering Corporation, Kellogg Brown & Root International, Inc. (a Delaware corporation), Kellogg Brown & Root International, Inc. (a Panamanian corporation), and BPM Minerals, LLC under Chapter 11 of the United States Bankruptcy Code dated September 18, 2003 (incorporated by reference to Exhibit 99 to Halliburton’s Form 8 - -K dated as of September 22, 2003, File No. 1-3492).

2.2 Supplemental Disclosure Statement for First Amended Joint Pre-packaged Plan of Reorganization for Mid-Valley, Inc., DII Industries, LLC, Kellogg Brown & Root, Inc., KBR Technical Services, Inc., Kellogg Brown & Root Engineering Corporation, Kellogg Brown & Root International, Inc. (a Delaware corporation), Kellogg Brown & Root International, Inc. (a Panamanian corporation), and BPM Minerals, LLC under Chapter 11 of the United States Bankruptcy Code dated November 14, 2003 (incorporated by reference to Exhibit 99 to Halliburton& #146;s Form 8-K dated as of November 19, 2003, File No. 1-3492).

3.1 Restated Certificate of Incorporation of Halliburton Company filed with the Secretary of State of Delaware on May 21, 2004 (incorporated by reference to Exhibit 3.1 to Halliburton’s Registration Statement on Form S-4 filed on July 19, 2004, Registration No. 333-112977).


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3.2 By-laws of Halliburton revised effective February 12, 2003 (incorporated by reference to Exhibit 3.2 to Halliburton’s Form 10-K for the year ended December 31, 2002, File No. 1-3492).

4.1 Form of debt security of 8.75% Debentures due February 12, 2021 (incorporated by reference to Exhibit 4(a) to the Form 8-K of Halliburton Company, now known as Halliburton Energy Services, Inc. (the Predecessor) dated as of February 20, 1991, File No. 1-3492).

4.2 Senior Indenture dated as of January 2, 1991 between the Predecessor and Texas Commerce Bank National Association, as Trustee (incorporated by reference to Exhibit 4(b) to the Predecessor’s Registration Statement on Form S-3 (Registration No. 33-38394) originally filed with the Securities and Exchange Commission on December 21, 1990), as supplemented and amended by the First Supplemental Indenture dated as of December 12, 1996 among the Predecessor, Halliburton and the Trustee (incorporated by reference to Exhibit 4.1 of Halliburton’ s Registration Statement on Form 8-B dated December 12, 1996, File No. 1-3492).

4.3 Resolutions of the Predecessor’s Board of Directors adopted at a meeting held on February 11, 1991 and of the special pricing committee of the Board of Directors of the Predecessor adopted at a meeting held on February 11, 1991 and the special pricing committee’s consent in lieu of meeting dated February 12, 1991 (incorporated by reference to Exhibit 4(c) to the Predecessor’s Form 8-K dated as of February 20, 1991, File No. 1-3492).

4.4 Second Senior Indenture dated as of December 1, 1996 between the Predecessor and Texas Commerce Bank National Association, as Trustee, as supplemented and amended by the First Supplemental Indenture dated as of December 5, 1996 between the Predecessor and the Trustee and the Second Supplemental Indenture dated as of December 12, 1996 among the Predecessor, Halliburton and the Trustee (incorporated by reference to Exhibit 4.2 of Halliburton’s Registration Statement on Form 8-B dated December 12, 1996, File No. 1-3492).

4.5 Third Supplemental Indenture dated as of August 1, 1997 between Halliburton and Texas Commerce Bank National Association, as Trustee, to the Second Senior Indenture dated as of December 1, 1996 (incorporated by reference to Exhibit 4.7 to Halliburton’s Form 10-K for the year ended December 31, 1998, File No. 1-3492).

4.6 Fourth Supplemental Indenture dated as of September 29, 1998 between Halliburton and Chase Bank of Texas, National Association (formerly Texas Commerce Bank National Association), as Trustee, to the Second Senior Indenture dated as of December 1, 1996 (incorporated by reference to Exhibit 4.8 to Halliburton’s Form 10-K for the year ended December 31, 1998, File No. 1-3492).

4.7 Resolutions of Halliburton’s Board of Directors adopted by unanimous consent dated December 5, 1996 (incorporated by reference to Exhibit 4(g) of Halliburton’s Form 10-K for the year ended December 31, 1996, File No. 1-3492).


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4.8 Form of debt security of 6.75% Notes due February 1, 2027 (incorporated by reference to Exhibit 4.1 to Halliburton’s Form 8-K dated as of February 11, 1997, File No. 1-3492).

4.9 Resolutions of Halliburton’s Board of Directors adopted at a special meeting held on September 28, 1998 (incorporated by reference to Exhibit 4.10 to Halliburton’s Form 10-K for the year ended December 31, 1998, File No. 1-3492).

4.10 Restated Rights Agreement dated as of December 1, 1996 between Halliburton and Mellon Investor Services LLC (formerly ChaseMellon Shareholder Services, L.L.C.) (incorporated by reference to Exhibit 4.4 of Halliburton’s Registration Statement on Form 8-B dated December 12, 1996, File No. 1-3492).

4.11 Copies of instruments that define the rights of holders of miscellaneous long-term notes of Halliburton and its subsidiaries, totaling $12 million in the aggregate at December 31, 2004, have not been filed with the Commission. Halliburton agrees to furnish copies of these instruments upon request.

4.12 Form of debt security of 7.53% Notes due May 12, 2017 (incorporated by reference to Exhibit 4.4 to Halliburton’s Form 10-Q for the quarter ended March 31, 1997, File No. 1-3492).

4.13 Form of debt security of 5.63% Notes due December 1, 2008 (incorporated by reference to Exhibit 4.1 to Halliburton’s Form 8-K dated as of November 24, 1998, File No. 1-3492).

4.14 Form of Indenture, between Dresser and Texas Commerce Bank National Association, as Trustee, for 7.60% Debentures due 2096 (incorporated by reference to Exhibit 4 to the Registration Statement on Form S-3 filed by Dresser as amended, Registration No. 333-01303), as supplemented and amended by Form of Supplemental Indenture, between Dresser and Texas Commerce Bank National Association, Trustee, for 7.60% Debentures due 2096 (incorporated by reference to Exhibit 4.1 to Dresser’s Form 8-K filed on August 9, 1996, File No. 1-4003).

4.15 Second Supplemental Indenture dated as of October 27, 2003 between DII Industries, LLC and JPMorgan Chase Bank, as Trustee, to the Indenture dated as of April 18, 1996, as supplemented by the First Supplemental Indenture dated as of August 6, 1996 (incorporated by reference to Exhibit 4.15 to Halliburton’s Form 10-K for the year ended December 31, 2003, File No. 1-3492).

4.16 Third Supplemental Indenture dated as of December 12, 2003 among DII Industries, LLC, Halliburton and JPMorgan Chase Bank, as Trustee, to the Indenture dated as of April 18, 1996, as supplemented by the First Supplemental Indenture dated as of August 6, 1996 and the Second Supplemental Indenture dated as of October 27, 2003 (incorporated by reference to Exhibit 4.16 to Halliburton’s Form 10-K for the year ended December 31, 2003, File No. 1-3492).

4.17 Form of debt security of 6% Notes due August 1, 2006 (incorporated by reference to Exhibit 4.2 to Halliburton’s Form 8-K dated January 8, 2002, File No. 1-3492).


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4.18 Credit Facility in the amount of £80 million dated November 29, 2002 between Devonport Royal Dockyard Limited and Devonport Management Limited and The Governor and Company of the Bank of Scotland, HSBC Bank Plc and The Royal Bank of Scotland Plc (incorporated by reference to Exhibit 4.22 to Halliburton’s Form 10-K for the year ended December 31, 2002, File No. 1-3492).

4.19 Senior Indenture dated as of June 30, 2003 between Halliburton and JPMorgan Chase Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Halliburton’s Form 10-Q for the quarter ended June 30, 2003, File No. 1-3492).

4.20 Form of note of 3.125% Convertible Senior Notes due July 15, 2023 (included as Exhibit A to Exhibit 4.19 above).

4.21 Registration Rights Agreement dated as of June 30, 2003 among Halliburton and Citigroup Global Markets, Inc., Goldman, Sachs & Co. and J.P. Morgan Securities Inc., as representatives of the several Purchasers named in Schedule I of the Purchase Agreement dated as of June 24, 2003 (incorporated by reference to Exhibit 4.3 to Halliburton’s Registration Statement on Form S-3, Registration No. 333-110035).

4.22 First Supplemental Indenture dated as of December 17, 2004 between Halliburton and JPMorgan Chase Bank, National Association (formerly JPMorgan Chase Bank), as trustee, to Indenture dated as of June 30, 2003, between Halliburton and JPMorgan Chase Bank, National Association (formerly JPMorgan Chase Bank), as trustee (incorporated by reference to Exhibit 4.1 to Halliburton’s Form 8-K filed on December 21, 2004, File No. 1-3492).

4.23 Senior Indenture dated as of October 17, 2003 between Halliburton and JPMorgan Chase Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Halliburton’s Form 10-Q for the quarter ended September 30, 2003, File No. 1-3492).

4.24 First Supplemental Indenture dated as of October 17, 2003 between Halliburton and JPMorgan Chase Bank, as Trustee, to the Senior Indenture dated as of October 17, 2003 (incorporated by reference to Exhibit 4.2 to Halliburton’s Form 10-Q for the quarter ended September 30, 2003, File No. 1-3492).

4.25 Form of note of floating-rate senior notes due October 17, 2005 (included as Exhibit A to Exhibit 4.24 above).

4.26 Form of note of 5.5% senior notes due October 15, 2010 (included as Exhibit B to Exhibit 4.24 above).

4.27 Registration Rights Agreement dated as of October 17, 2003 among Halliburton and J.P. Morgan Securities Inc., Citigroup Global Markets, Inc. and Goldman, Sachs & Co., as representatives of the several Purchasers named in Schedule I of the Purchase Agreement dated as of October 14, 2003 (incorporated by reference to Exhibit 4.5 to Halliburton’s Registration Statement on Form S-4, Registration No. 333-110420).


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4.28 Second Supplemental Indenture dated as of December 15, 2003 between Halliburton and JPMorgan Chase Bank, as Trustee, to the Senior Indenture dated as of October 17, 2003, as supplemented by the First Supplemental Indenture dated as of October 17, 2003 (incorporated by reference to Exhibit 4.27 to Halliburton’s Form 10-K for the year ended December 31, 2003, File No. 1-3492).

4.29 Form of note of 7.6% debentures due 2096 (included as Exhibit A to Exhibit 4.28 above).

4.30 Third Supplemental Indenture dated as of January 26, 2004 between Halliburton and JPMorgan Chase Bank, as Trustee, to the Senior Indenture dated as of October 17, 2003, as supplemented by the First Supplemental Indenture dated as of October 17, 2003 and the Second Supplemental Indenture dated as of December 15, 2003 (incorporated by reference to Exhibit 4.2 to Halliburton’s Registration Statement on Form S-4, Registration No. 333-112977).

4.31 Form of Senior Notes due 2007 (included as Exhibit A to Exhibit 4.30 above).

4.32 Registration Rights Agreement dated as of January 26, 2004 among Halliburton and J.P. Morgan Securities Inc., Citigroup Global Markets, Inc. and Goldman, Sachs & Co., as representatives of the several Purchasers named in Schedule I of the Purchase Agreement dated as of January 21, 2004 (incorporated by reference to Exhibit 4.4 to Halliburton’s Registration Statement on Form S-4, Registration No. 333-112977).

4.33 Stockholder Agreement between Halliburton and the DII Industries, LLC Asbestos PI Trust dated January 20, 2005 (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K filed January 25, 2005, File No. 1-3492).

10.1 Halliburton Company Career Executive Incentive Stock Plan as amended November 15, 1990 (incorporated by reference to Exhibit 10(a) to the Predecessor’s Form 10-K for the year ended December 31, 1992, File No. 1-3492).

10.2 Retirement Plan for the Directors of Halliburton Company, as amended and restated effective May 16, 2000 (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 10-Q for the quarter ended September 30, 2000, File No. 1-3492).

10.3 Halliburton Company Directors’ Deferred Compensation Plan as amended and restated effective February 1, 2001 (incorporated by reference to Exhibit 10.3 to Halliburton’s Form 10-K for the year ended December 31, 2000, File No. 1-3492).

10.4 Halliburton Company 1993 Stock and Incentive Plan, as amended and restated effective May 18, 2004 (incorporated by reference to Exhibit 10.5 to Halliburton’s Form 10-Q for the quarter ended June 30, 2004, File No. 1-3492).

10.5 Halliburton Company Restricted Stock Plan for Non-Employee Directors (incorporated by reference to Appendix B of the Predecessor’s proxy statement dated March 23, 1993, File No. 1-3492).


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10.6 Dresser Industries, Inc. Deferred Compensation Plan, as amended and restated effective January 1, 2000 (incorporated by reference to Exhibit 10.16 to Halliburton’s Form 10-K for the year ended December 31, 2000, File No. 1-3492).

10.7 Dresser Industries, Inc. 1982 Stock Option Plan (incorporated by reference to Exhibit A to Dresser’s Proxy Statement dated February 12, 1982, File No. 1-4003).

10.8 ERISA Excess Benefit Plan for Dresser Industries, Inc., as amended and restated effective June 1, 1995 (incorporated by reference to Exhibit 10.7 to Dresser’s Form 10-K for the year ended October 31, 1995, File No. 1-4003).

10.9 ERISA Compensation Limit Benefit Plan for Dresser Industries, Inc., as amended and restated effective June 1, 1995 (incorporated by reference to Exhibit 10.8 to Dresser’s Form 10-K for the year ended October 31, 1995, File No. 1-4003).

10.10 Supplemental Executive Retirement Plan of Dresser Industries, Inc., as amended and restated effective January 1, 1998 (incorporated by reference to Exhibit 10.9 to Dresser’s Form 10-K for the year ended October 31, 1997, File No. 1-4003).

10.11 Amendment No. 1 to the Supplemental Executive Retirement Plan of Dresser Industries, Inc. (incorporated by reference to Exhibit 10.1 to Dresser’s Form 10-Q for the quarter ended April 30, 1998, File No. 1-4003).

10.12 Stock Based Compensation Arrangement of Non-Employee Directors (incorporated by reference to Exhibit 4.4 to Dresser’s Registration Statement on Form S-8, Registration No. 333-40829).

10.13 Dresser Industries, Inc. Deferred Compensation Plan for Non-Employee Directors, as restated and amended effective November 1, 1997 (incorporated by reference to Exhibit 4.5 to Dresser’s Registration Statement on Form S-8, Registration No. 333-40829).

10.14 Long-Term Performance Plan for Selected Employees of The M. W. Kellogg Company, as amended and restated effective September 1, 1999 (incorporated by reference to Exhibit 10.23 to Halliburton’s Form 10-K for the year ended December 31, 2000, File No. 1-3492).

10.15 Dresser Industries, Inc. 1992 Stock Compensation Plan (incorporated by reference to Exhibit A to Dresser’s Proxy Statement dated February 7, 1992, File No. 1-4003).

10.16 Amendments No. 1 and 2 to Dresser Industries, Inc. 1992 Stock Compensation Plan (incorporated by reference to Exhibit A to Dresser’s Proxy Statement dated February 6, 1995, File No. 1-4003).

10.17 Amendment No. 3 to the Dresser Industries, Inc. 1992 Stock Compensation Plan (incorporated by reference to Exhibit 10.25 to Dresser’s Form 10-K for the year ended October 31, 1997, File No. 1-4003).


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10.18 Employment Agreement (David J. Lesar) (incorporated by reference to Exhibit 10(n) to the Predecessor’s Form 10-K for the year ended December 31, 1995, File No. 1-3492).

10.19 Employment Agreement (Mark A. McCollum) (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 10-Q for the quarter ended September 30, 2003, File No. 1-3492).

10.20 Halliburton Company Supplemental Executive Retirement Plan (formerly part of Halliburton Company Senior Executives’ Deferred Compensation Plan), as amended and restated effective January 1, 2001 (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 10-Q for the quarter ended June 30, 2001, File No. 1-3492).

10.21 Halliburton Company Benefit Restoration Plan, as amended and restated effective January 1, 2004 (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 10-Q for the quarter ended September 30, 2004, File No. 1-3492).

10.22 Halliburton Annual Performance Pay Plan, as amended and restated effective January 1, 2001 (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 10-Q for the quarter ended September 30, 2001, File No. 1-3492).

10.23 Halliburton Company Performance Unit Program (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 10-Q for the quarter ended September 30, 2001, File No. 1-3492).

10.24 Form of Nonstatutory Stock Option Agreement for Non-Employee Directors (incorporated by reference to Exhibit 10.3 to Halliburton’s Form 10-Q for the quarter ended September 30, 2000, File No. 1-3492).

10.25 Halliburton Elective Deferral Plan as amended and restated effective May 1, 2002 (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 10-Q for the quarter ended June 30, 2002, File No. 1-3492).

10.26 Halliburton Company 2002 Employee Stock Purchase Plan, as amended and restated September 9, 2004 (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 10-Q for the quarter ended September 30, 2004, File No. 1-3492).

10.27 Halliburton Company Directors’ Deferred Compensation Plan as amended and restated effective as of October 22, 2002 (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 10-Q for the quarter ended September 30, 2002, File No. 1-3492).

10.28 Employment Agreement (Albert O. Cornelison) (incorporated by reference to Exhibit 10.3 to Halliburton’s Form 10-Q for the quarter ended June 30, 2002, File No. 1-3492).

10.29 Employment Agreement (Weldon J. Mire) (incorporated by reference to Exhibit 10.4 to Halliburton’s Form 10-Q for the quarter ended June 30, 2002, File No. 1-3492).


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10.30 Employment Agreement (David R. Smith) (incorporated by reference to Exhibit 10.39 to Halliburton’s Form 10-K for the year ended December 31, 2002, File No. 1-3492).

10.31 Employment Agreement (John W. Gibson) (incorporated by reference to Exhibit 10.40 to Halliburton’s Form 10-K for the year ended December 31, 2002, File No. 1-3492).

10.32 Employment Agreement (C. Christopher Gaut) (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 10-Q for the quarter ended March 31, 2003, File No. 1-3492).

10.33 3-Year Revolving Credit Agreement, dated as of October 31, 2003, among Halliburton, the Banks party thereto, Citicorp North America, Inc., as Administrative Agent, JPMorgan Chase Bank, as Syndication Agent, and ABN AMRO Bank N.V., as Documentation Agent (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 10-Q for the quarter ended September 30, 2003, File No. 1-3492).

10.34 Amendment No. 1 dated as of July 14, 2004 to the 3-Year Revolving Credit Agreement, dated as of October 31, 2003, among Halliburton, the Banks party thereto, Citicorp North America, Inc., as Administrative Agent, JPMorgan Chase Bank, as Syndication Agent, and ABN AMRO Bank N.V., as Documentation Agent (incorporated by reference to Exhibit 10.1(a) of Halliburton’s Registration Statement on Form S-4 filed on July 19, 2004, Registration No. 333-112977).

10.35 Amendment No. 2 to 3-Year Revolving Credit Agreement dated as of October 31, 2003, as amended, among Halliburton, the Banks party thereto, Citicorp North America, Inc., as Administrative Agent, JPMorgan Chase Bank, as Syndication Agent, and ABN AMRO Bank N.V., as Documentation Agent (incorporated by reference to Exhibit 10.2 to Halliburton’s Form 8-K filed December 30, 2004, File No. 1-3492).

10.36 Master Letter of Credit Facility Agreement, dated as of October 31, 2003, among Halliburton, Kellogg Brown & Root, Inc., and DII Industries, LLC, as Account Parties, the Banks party thereto, Citicorp North America, Inc., as Administrative Agent, JPMorgan Chase Bank, as Syndication Agent, and ABN AMRO Bank N.V., as Documentation Agent (incorporated by reference to Exhibit 10.3 to Halliburton’s Form 10-Q for the quarter ended September 30, 2003, File No. 1-3492).

10.37 Amendment No. 1 dated as of May 10, 2004 to Master Letter of Credit Facility Agreement, dated as of October 31, 2003, among Halliburton, Kellogg Brown & Root, Inc., and DII Industries, LLC, as Account Parties, the Banks party thereto, and Citicorp North America, Inc., as Administrative Agent, JPMorgan Chase Bank, as Syndication Agent, and ABN AMRO Bank N.V., as Documentation Agent, as amended (incorporated by reference to Exhibit 10.4 of Halliburton’s Registration Statement on Form S-4 filed on June 3, 2004, Registration No. 333-112977).


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10.38 Amendment No. 2 dated as of July 14, 2004 to the Master Letter of Credit Facility Agreement, dated as of October 31, 2003, among Halliburton, Kellogg Brown & Root, Inc., and DII Industries, LLC, as Account Parties, the Banks party thereto, Citicorp North America, Inc., as Administrative Agent, JPMorgan Chase Bank, as Syndication Agent, and ABN AMRO Bank N.V., as Documentation Agent, as amended (incorporated by reference to Exhibit 10.2(a) of Halliburton’s Registration Statement on Form S-4 filed on July 19, 2004, Registration No. 333-112977).

10.39 Amendment No. 3 to the Master Letter of Credit Facility Agreement dated as of October 31, 2003 among Halliburton, certain subsidiaries of Halliburton, the Banks party thereto, Citicorp North America, Inc., as Administrative Agent, JPMorgan Chase Bank, as Syndication Agent, and ABN AMRO Bank, N.V., as Documentation Agent (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K filed December 15, 2004, File No. 1-3492).

10.40 Amendment No. 4 to the Master Letter of Credit Facility Agreement dated as of October 31, 2003, as amended, among Halliburton, certain subsidiaries of Halliburton, the Banks party thereto, Citicorp North America, Inc., as Administrative Agent, JPMorgan Chase Bank, as Syndication Agent, and ABN AMRO Bank, N.V., as Documentation Agent (incorporated by reference to Exhibit 10.1 to Halliburton’s Form 8-K filed December 30, 2004, File No. 1-3492).

10.41 Senior Unsecured Credit Facility Agreement, dated as of November 4, 2003, among Halliburton, the Banks party thereto, Citicorp North America, Inc., as Administrative Agent, JPMorgan Chase Bank, as Syndication Agent, and ABN AMRO Bank N.V., as Documentation Agent (incorporated by reference to Exhibit 10.4 to Halliburton’s Form 10-Q for the quarter ended September 30, 2003, File No. 1-3492).

10.42 364-Day Revolving Credit Agreement, dated as of July 14, 2004, among Halliburton, the Issuing Banks and Banks Party thereto, Citicorp North America, Inc., as Paying Agent and as Co-Administrative Agent, JPMorgan Chase Bank, as Co-Administrative Agent, ABN AMRO Bank N.V., as Syndication Agent, and HSBC Bank USA, National Association and The Royal Bank of Scotland plc, as Co-Documentation Agents (incorporated by reference to Exhibit 10.3 of Halliburton’s Registration Statement on Form S-4 filed on July 19, 2004, Registration No. 333-112977).

10.43 Amendment No. 1 to 364-Day Revolving Credit Agreement dated as of July 14, 2004, among Halliburton, the Banks party thereto, Citicorp North America, Inc., as Paying Agent, JPMorgan Chase Bank, as Co-Administrative Agent, ABN AMRO Bank N.V., as Sydication Agent, and HSBC Bank USA, National Association and The Royal Bank of Scotland plc, as Co-Documentation Agents (incorporated by reference to Exhibit 10.3 to Halliburton’s Form 8-K filed December 30, 2004, File No. 1-3492).

10.44 Employment Agreement (Andrew R. Lane)(incorporated by reference to Exhibit 10.3 to Halliburton’s Form 10-Q for the quarter ended September 30, 2004, File No. 1-3492).


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* 12 Statement of Computation of Ratio of Earnings to Fixed Charges.

* 21 Subsidiaries of the Registrant.

* 23.1 Consent of KPMG LLP.

24.1 Powers of attorney for the following directors signed in January 2004 (incorporated by reference to Exhibit 24.1 to Halliburton’s Form 10-K for the year ended December 31, 2003, File No. 1-3492):

Robert L. Crandall

Kenneth T. Derr

Charles J. DiBona

W. R. Howell

Ray L. Hunt

Aylwin B. Lewis

J. Landis Martin

Jay A. Precourt

Debra L. Reed

C. J. Silas

* 31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

* 31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

** 32.1 Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

** 32.2 Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed with this Form 10-K.

** Furnished with this Form 10-K.


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ON SUPPLEMENTAL SCHEDULE

The Board of Directors and Shareholders

Halliburton Company:

Under date of February 25, 2005, we reported on the consolidated balance sheets of Halliburton Company and subsidiaries as of December 31, 2004 and December 31, 2003, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2004, which are included in the Annual Report on Form 10-K. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related consolidated financial statement schedule (Schedule II) included in the Annual Report on Form 10-K. The financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statement schedule based on our audits.

In our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ KPMG LLP

Houston, Texas

February 25, 2005


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HALLIBURTON COMPANY

Schedule II - Valuation and Qualifying Accounts

(Millions of Dollars)

The table below presents valuation and qualifying accounts for continuing operations.

			Additions
	Balance at		Charged to		Charged to					Balance at
	Beginning		Costs and		Other					End of
Descriptions	of Period		Expenses		Accounts		Deductions			Period
Year ended December 31, 2002:
Deducted from accounts and notes receivable:
Allowance for bad debts	$	131	$	82	$	-	$	(56) (a	)	$	157
Accrued reorganization charges	$	1	$	29	$	-	$	(20) (b	)	$	10

Year ended December 31, 2003:
Deducted from accounts and notes receivable:
Allowance for bad debts	$	157	$	44	$	4	$	(30) (a	)	$	175
Accrued reorganization charges	$	10	$	-	$	-	$	(9) (b	)	$	1

Year ended December 31, 2004:
Deducted from accounts and notes receivable:
Allowance for bad debts	$	175	$	22	$	2	$	(72) (a	)	$	127
Accrued reorganization charges	$	1	$	40	$	-	$	(22) (b	)	$	19

(a) Receivable write-offs, reclassifications, and net of recoveries.

(b) See Note 21 to the consolidated financial statements for more information.


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SIGNATURES

As required by Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has authorized this report to be signed on its behalf by the undersigned authorized individuals, on this 1st day of March, 2005.

HALLIBURTON COMPANY

By	/s/ David J. Lesar
	David J. Lesar
	Chairman of the Board,
	President and Chief Executive Officer

As required by the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities indicated on this 1st day of March, 2005.

Signature	Title




/s/ David J. Lesar	Chairman of the Board, President,
David J. Lesar	Chief Executive Officer, and Director




/s/ C. Christopher Gaut	Executive Vice President and
C. Christopher Gaut	Chief Financial Officer




/s/ Mark A. McCollum	Senior Vice President and
Mark A. McCollum	Chief Accounting Officer


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Signature	Title

* Robert L. Crandall	Director
Robert L. Crandall

* Kenneth T. Derr	Director
Kenneth T. Derr

* Charles J. DiBona	Director
Charles J. DiBona

* W. R. Howell	Director
W. R. Howell

* Ray L. Hunt	Director
Ray L. Hunt

* Aylwin B. Lewis	Director
Aylwin B. Lewis

* J. Landis Martin	Director
J. Landis Martin

* Jay A. Precourt	Director
Jay A. Precourt

* Debra L. Reed	Director
Debra L. Reed

* C. J. Silas	Director
C. J. Silas




* /s/ Margaret E. Carriere
Margaret E. Carriere, Attorney-in-fact


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Statement of Computation of Ratio of Earnings to Fixed Charges

Exhibit 12

HALLIBURTON COMPANY

Computation of Ratio of Earnings to Fixed Charges

(Millions of dollars, except for ratios)

(Unaudited)

	Years Ended December 31
	2004		2003		2002			2001		2000
Earnings available for fixed charges:
Income (loss) from continuing
operations before income
taxes, minority interests,
and cumulative effects of
accounting changes, net	$	651	$	612	$	(228	)	$	954	$	335
Add:
Distributed earnings from
equity in unconsolidated
affiliates		61		113		33			38		34
Fixed charges		295		203		168			209		203
Subtotal		1,007		928		(27	)		1,201		572
Less:
Undistributed equity in
earnings and losses of
unconsolidated affiliates		2		25		74			107		88
Total	$	1,005	$	903	$	(101	)	$	1,094	$	484

Fixed charges:
Interest expense	$	229	$	139	$	113		$	147	$	146
Rental expense representative
of interest		66		64		55			62		57
Total	$	295	$	203	$	168		$	209	$	203

Ratio of earnings to fixed charges		3.4		4.4		(a	)		5.2		2.4

(a) For the year ended December 31, 2002, earnings were inadequate to cover fixed charges by $269 million.

Subsidiaries of the Registrant

	Exhibit 21
HALLIBURTON COMPANY
Subsidiaries of the Registrant
December 31, 2004

	STATE OR COUNTRY
NAME OF COMPANY	OF INCORPORATION

BITC (US) LLC	United States
Breswater Marine Contracting B.V.	Netherlands
Devonport Management Limited	United Kingdom
Devonport Royal Dockyard Limited	United Kingdom
DII Industries, LLC	United States
Georgetown Finance Ltd.	Cayman Islands
Halliburton Affiliates, LLC	United States
Halliburton AS	Norway
Halliburton Canada Holdings, Inc.	United States
Halliburton Energy Cayman Islands Limited	Cayman Islands
Halliburton Energy Services, Inc.	United States
Halliburton Group Canada Inc.	Canada
Halliburton Group Holdings (1) Company	Canada
Halliburton Holdings (No. 2) Limited	United Kingdom
Halliburton Holdings (No. 3)	United Kingdom
Halliburton Interim, Inc.	United States
Halliburton International, Inc.	United States
Halliburton Manufacturing and Services Limited	United Kingdom
Halliburton Netherlands Operations Cooperatie	Netherlands
Halliburton Norway Holdings C.V.	Netherlands
Halliburton Produtos Ltda.	Brazil
Hobbymarkt Delft BV	Netherlands
KBR Group Holdings, LLC	United States
Kellogg Brown & Root Holdings (U.K.) Limited	United Kingdom
Kellogg Brown & Root Holdings Limited	United Kingdom
Kellogg Brown & Root International, Inc. (A Delaware Corporation)	United States
Kellogg Brown & Root Limited	United Kingdom
Kellogg Brown & Root, Inc.	United States
Kellogg Brown & Root Services, Inc.	United States
Petroleum Engineering Services Norge AS	Norway

Exhibit 23-1_Consent of KPMG

Exhibit 23-1

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Halliburton Company:

We consent to the incorporation by reference in the registration statements (Nos. 33-65772, 333-32731, 333-74408, 333-110035, 333-120646 and 333-120652) on Form S-3, (No. 333-110420) on Form S-4 and (Nos. 33-54881, 333-40717, 333-37533, 333-13475, 333-65373, 333-55747, 333-83223, 333-45518, 333-73046, 333-76496, 333-91058, and 333-86080) on Form S-8 of Halliburton Company of our reports dated February 25, 2005, with respect to the consolidated balance sheets of Halliburton Company as of December 31, 2004 and 2003, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2004, management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2004 and the effectiveness of inte rnal control over financial reporting as of December 31, 2004, which reports appear in the December 31, 2004 annual report on Form 10-K of Halliburton Company.

Our report contains an explanatory paragraph that states the Company changed the composition of its reportable segments in 2004 and 2003, as described in Note 5 to the consolidated financial statements. The amounts in the 2003 and 2002 consolidated financial statements related to reportable segments have been restated to conform to the 2004 composition of reportable segments.

/s/ KPMG LLP

Houston, Texas

February 25, 2005

Exhibit 31-1_302 Certification_Lesar

Exhibit 31.1

Section 302 Certification

I, David J. Lesar, certify that:

1. I have reviewed this annual report on Form 10-K for the year 2004 of Halliburton Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 1, 2005

/s/ David J. Lesar_______

David J. Lesar

Chief Executive Officer

Halliburton Company

Exhibit 31-2_302 Certification_Gaut

Exhibit 31.2

Section 302 Certification

I, C. Christopher Gaut, certify that:

1. I have reviewed this annual report on Form 10-K for the year 2004 of Halliburton Company;

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 1, 2005

/s/ C. Christopher Gaut_____

C. Christopher Gaut

Chief Financial Officer

Halliburton Company

Exhibit 32-1_906 Certification_Lesar

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

This certification is provided pursuant to § 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. § 1350, and accompanies the Annual Report on Form 10-K for the period ended December 31, 2004 of Halliburton Company (the “Company”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”).

I, David J. Lesar, Chief Executive Officer of the Company, certify that:

(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ David J. Lesar_________

David J. Lesar

Chief Executive Officer

Date: March 1, 2005

Exhibit 32-2_906 Certification_Gaut

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, C. Christopher Gaut, Chief Financial Officer of the Company, certify that:

(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ C. Christopher Gaut_____

C. Christopher Gaut

Chief Financial Officer

Date: March 1, 2005